Item 1B.
Unresolved Staff Comments.
Not applicable.
Item 3.
Item 3.
Legal Proceedings.
We are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.
Item 4.
Item 4.
Mine Safety Disclosures.
Not applicable.
PART II
Item 5.
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market For Registrant’s Common Equity
Our common stock is listed on the New York Stock Exchange under the symbol "BBG".
The range of high and low sales prices for our common stock for the two most recent fiscal years as reported by the New York Stock Exchange was as follows:
On January 27, 2015, the closing sales price for our common stock as reported by the NYSE was $10.82 per share.
Holders. On January 27, 2015, the number of holders of record of our common stock was 110.
Dividends. We have not paid any cash dividends since our inception. Because we anticipate that all earnings will be retained for the development of our business and our debt agreements prohibit the payment of cash dividends, we do not expect that any cash dividends will be paid on our common stock for the foreseeable future.
Unregistered Sales of Securities. There were no sales of unregistered equity securities during the year ended December 31, 2014.
Issuer Purchases of Equity Securities. The following table contains information about our acquisitions of equity securities during the three months ended December 31, 2014:
(1)
Represents shares delivered by employees to satisfy the exercise price of stock options and tax withholding obligations in connection with the exercise of stock options and shares withheld from employees to satisfy tax withholding obligations in connection with the vesting of shares of restricted common stock issued pursuant to our employee incentive plans.
Stockholder Return Performance Presentation
As required by applicable rules of the SEC, the performance graph shown below was prepared based upon the following assumptions:
1.
$100 was invested in our common stock on December 31, 2009, and $100 was invested in each of the Standard & Poors 500 Index and the Standard & Poors MidCap 400 Index-Energy Sector at the closing price on December 31, 2009.
2.
Dividends are reinvested on the ex-dividend dates.
Item 6.
Item 6.
Selected Financial Data.
The following table presents our selected historical financial data for the years ended December 31, 2014, 2013, 2012, 2011 and 2010. Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines and other factors. This information should be read in conjunction with the consolidated financial statements and notes thereto and "Item 7.
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations.
Introduction
The following discussion and analysis should be read in conjunction with the "Selected Financial Data" and the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. See the "Cautionary Note Regarding Forward-Looking Statements" at the beginning of this Annual Report on Form 10-K. Forward-looking statements are not guarantees of future performance and our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in "Items 1 and 2. Business and Properties - Business - Operations - Environmental Matters and Regulation;" "Items 1 and 2. Business and Properties - Business - Operations - Other Regulation of the Oil and Gas Industry;" and "Item 1A. Risk Factors" above, all of which are incorporated herein by reference. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.
Overview
We develop oil and natural gas in the Rocky Mountain region of the United States. We seek to build stockholder value by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize operations while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices.
We were formed in January 2002 and are incorporated in the State of Delaware. In December 2004, we completed our initial public offering of 14,950,000 shares of our common stock at a price to the public of $25.00 per share.
We are committed to developing and producing oil and natural gas in a responsible and safe manner. Our employees work diligently with regulatory agencies, as well as environmental, wildlife and community organizations, to ensure that exploration and development activities meet stakeholders expectations and regulatory requirements.
While there are currently no unannounced agreements for the acquisition of any material businesses or assets, future acquisitions or dispositions could have a material impact on our financial condition and results of operations by increasing or decreasing our reserves, production and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with available borrowings under our Amended Credit Facility, sales of properties, other indebtedness, and/or debt, equity or equity-linked securities. Our prior acquisitions and capital expenditures were financed with a combination of cash on hand, funding from the sale of our equity securities, our Amended Credit Facility, other debt financing and cash flows from operations.
Beginning January 1, 2013, we modified our gas processing agreements with various processors to take title to NGLs resulting from the processing of our natural gas. Therefore, we report below reserve and production data for oil, natural gas and NGLs for periods after January 1, 2013. This is known as "three streams reporting". For periods prior to January 1, 2013, we presented our production and reserve data for oil and natural gas, which included NGLs in the natural gas stream. This change impacts the comparability of 2013 and 2014 production and reserves with those reported for prior periods.
Because of our growth through acquisitions and, more recently, development of our properties and sales of properties in 2012, 2013 and 2014, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful. In addition, past results are not indicative of future results.
The following table summarizes the estimated net proved reserves and related Standardized Measure for the years indicated. The Standardized Measure is not intended to represent the current market value of our estimated oil and natural gas reserves.
(1)
December 31, 2014 reserves were based on average prices of $94.99 WTI for oil, $4.35 Henry Hub for natural gas and $39.65 for NGLs. December 31, 2013 reserves were based on average prices of $96.91 WTI for oil, $3.67 Henry Hub for natural gas and $39.75 for NGLs. December 31, 2012 reserves were based on average prices of $2.56 CIG for natural gas and $91.21 WTI for oil.
The following table summarizes the average sales prices received for oil, natural gas and NGLs, before the effects of hedging contracts, for the years indicated:
(1)
Prior to 2013, NGL volumes and revenues were included within natural gas production data, which impacts the comparability for the period presented.
The following table summarizes the average sales prices received for oil, natural gas and NGLs, after the effects of hedging contracts, for the years indicated:
(1)
Prior to 2013, NGL volumes and revenues were included within natural gas production data, which impacts the comparability for the period presented.
Commodity prices are inherently volatile and are influenced by many factors outside of our control. We plan our activities and capital budget using what we believe to be conservative sales price assumptions and our existing hedge position. Our strategic objective is to hedge 50% to 70% of our anticipated production on a forward 12-month to 18-month basis using a combination of swaps and other financial derivative instruments. We currently have hedged approximately 90% of our expected 2015 production at price levels that provide some economic certainty. We focus our efforts on increasing oil, natural gas and NGLs reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our revenues and overall cost structure to a level that allows for profitable production.
Like all oil and gas exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil, gas and NGLs production from a typical well naturally decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. See "- Trends and Uncertainties - Regulatory Trends" below. The permitting and approval process has been more difficult in recent years than in the past due to more stringent rules, such as those enacted by the COGCC in 2009, and increased activism from environmental and other groups, which has extended the time it takes us to receive permits and other necessary approvals. Because of our relatively small size and concentrated property base, we can be disproportionately disadvantaged by delays in obtaining or failing to obtain drilling approvals compared to companies with larger or more dispersed property bases. As a result, we may be less able to shift drilling activities to areas where permitting may be easier, and we have fewer properties over which to spread the costs related to complying with these regulations and the costs or foregone opportunities resulting from delays.
Results of Operations
Year Ended December 31, 2014 Compared with Year Ended December 31, 2013
The following table sets forth selected operating data for the periods indicated:
*
Not meaningful.
(1)
Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense for a total of $53.4 million and $64.9 million for the years ended December 31, 2014 and 2013, respectively, in the Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with stock-based grants.
(2)
Average realized prices shown in the table are net of the effects of all settled commodity hedging transactions related to current period production.
(3)
Excludes non-cash stock-based compensation expense as described in Note 1 above. This presentation is a non-GAAP measure. Average costs per Boe for general and administrative expense, including non-cash stock-based compensation
expense, as presented in the Consolidated Statements of Operations, were $5.86 and $4.48 for the years ended December 31, 2014 and 2013, respectively.
Production Revenues and Volumes. Production revenues decreased to $464.1 million for the year ended December 31, 2014 from $565.6 million for the year ended December 31, 2013. The decrease in production revenues was primarily due to a 37% decrease in production volumes, offset by an increase in the average price per Boe. The decrease in production volumes reduced production revenues by approximately $273.3 million, while the increase in average prices increased production revenues by approximately $171.8 million.
We discontinued hedge accounting as of January 1, 2012. All accumulated gains or losses related to the discontinued cash flow hedges were recorded in accumulated other comprehensive income ("AOCI") as of January 1, 2012 and remained in AOCI until the underlying transaction occurred. As the underlying transaction occurred, these gains or losses were reclassified from AOCI into oil, gas and NGL production revenues. The amount reclassified to oil, gas and NGL production revenues was a gain of $1.1 million and $7.5 million for the years ended December 31, 2014 and 2013, respectively. All cash flow hedge accounting transactions were completed as of December 31, 2014.
Total production volumes of 9.1 MMBoe for the year ended December 31, 2014 decreased from 14.5 MMBoe for the year ended December 31, 2013. The decrease is primarily related to sales of all of our natural gas assets in the West Tavaputs Divestiture on December 10, 2013 and in the Piceance Divestiture on September 30, 2014. These decreases were partially offset by a 118% overall increase in DJ Basin production. Additional information concerning production is in the following table:
*
Not meaningful.
(1)
Other for 2013 includes Uinta - West Tavaputs natural gas volumes of 21,714 MMcf and oil production of 30 MBbls.
Hedging Activities. In 2014, approximately 87% of our oil volumes, 87% of our natural gas volumes and 18% of our NGL related volumes were subject to financial hedges, which resulted in an increase in oil revenues of $6.4 million, offset by decreases in natural gas revenues of $7.1 million and NGL revenues of $0.1 million after settlements for all commodity derivatives. Of the loss on total settlements of $0.8 million for the year ended December 31, 2014, a gain of $1.1 million was included in oil, gas and NGL production revenues and a loss of $1.9 million was included in commodity derivative gain (loss) in the Consolidated Statements of Operations.
In 2013, approximately 83% of our oil volumes, 92% of our natural gas volumes and 16% of our NGL related volumes were subject to financial hedges, which resulted in a decrease in oil revenues of $0.8 million, offset by increases in natural gas revenues of $10.8 million and NGL revenues of $2.8 million after settlements for all commodity derivatives. Of the gain on total settlements of $12.8 million for the year ended December 31, 2013, a gain of $7.5 million was included in oil, gas and NGL production revenues and a gain of $5.3 million was included in commodity derivative gain (loss) in the Consolidated Statements of Operations.
Other Operating Revenues. Other operating revenues increased to $8.2 million for the year ended December 31, 2014 from $2.5 million for the year ended December 31, 2013. Other operating revenues for 2014 consisted of $5.9 million related to the recovery of processing deductions on NGL revenues and $2.3 million of income from gathering and compression fees received from third parties. The $5.9 million related to the recovery of processing deductions on NGL revenues is based on guidance provided by the Office of Natural Resources Revenue ("ONRR"). Additional processing deductions were taken
against NGL royalties paid on Federal and State leases from 2008 through July 2013 in the West Tavaputs area of the Uinta Basin and are now being recovered. The West Tavaputs properties were sold in December 2013.
Other operating revenues for 2013 consisted of $0.2 million in net gains realized from the sale of properties and $2.3 million of income from gathering, compression and salt water disposal fees received from third parties. The net realized gains from the sale of properties for the year ended December 31, 2013 related to a loss of $3.1 million from purchase price adjustments on the 2012 Divestiture, offset by a gain of $3.3 million from selldowns of other properties.
Lease Operating Expense. Lease operating expense ("LOE") increased to $6.62 per Boe for the year ended December 31, 2014 from $4.85 per Boe for the year ended December 31, 2013. LOE on a per Boe basis is inherently higher from our oil producing properties such as those in our Uinta Oil and DJ Basin development areas. Due to the sale of natural gas properties with lower LOE per Boe in the West Tavaputs and Piceance Divestitures, we expect higher LOE on a per Boe basis in future periods.
Gathering, Transportation and Processing Expense. Gathering, transportation and processing ("GTP") expense decreased to $3.89 per Boe for the year ended December 31, 2014 from $4.65 per Boe for the year ended December 31, 2013. GTP on a per Boe basis decreased due to inherently lower GTP from our oil producing properties such as those in our Uinta and DJ Basin development areas. Due to the sale of natural gas properties with higher GTP per Boe in the West Tavaputs and Piceance Divestitures, we expect lower GTP on a per Boe basis in future periods.
During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Accordingly, we will continue to incur monthly demand charges of approximately $1.5 million for the remaining term of six years even though we no longer utilizes these contracts. These costs were included in unused commitments in the Consolidated Statements of Operations after completion of the Piceance Divestiture on September 30, 2014.
Production Tax Expense. Total production taxes increased to $31.3 million for the year ended December 31, 2014 from $27.2 million for the year ended December 31, 2013. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes as a percentage of oil, natural gas and NGL sales before hedging adjustments were 6.8% and 4.9% for the years ended December 31, 2014 and December 31, 2013, respectively.
Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas. The increase in the overall production tax rate is consistent with our production increase in areas with higher production tax rates. With the sale of all of our natural gas properties as of December 31, 2014, which were in areas with lower production tax rates, we expect higher production tax rates in future periods.
Exploration Expense. Exploration expense for the year ended December 31, 2014 was $0.5 million compared to $0.3 million for the year ended December 31, 2013. Exploration expense for the year ended December 31, 2014 consisted of $0.3 million of geological and geophysical seismic programs and $0.2 million for delay rentals across all basins. Exploration expense for the year ended December 31, 2013 consisted of $0.3 million for delay rentals across all basins.
Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense for the twelve months ended December 31, 2014 and 2013 is summarized below:
We review our proved oil and natural gas properties for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and gas properties and compare these undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk associated with realizing the projected cash flows.
Unproved oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage and other relevant matters. We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities. If our attempts to market interests in certain properties to industry partners are unsuccessful, we may record additional leasehold impairments.
As the result of the Powder River Oil Divestiture, the carrying values of the remaining properties were analyzed relative to their estimated fair market values. As a result, the Company recognized impairment expense on proved properties of $14.8 million for the year ended December 31, 2014. These properties were classified as held for sale as of December 31, 2014. In addition, $1.0 million of proved property impairment expense was incurred during the year ended December 31, 2014 related to the West Tavaputs Divestiture based upon a true-up of previously estimated carrying value. See Note 4 of the Notes to Consolidated Financial Statements for more information related to these divestitures.
As a result of unsuccessful drilling and completion activity by an industry partner in the Paradox Basin, the Company recognized impairment expense of $11.6 million during the year ended December 31, 2014 related to the remaining unproved property in the Paradox Basin. The Company recognized impairment expense of $6.1 million related to certain unproved oil and gas properties in the Uinta Basin as a result of having no future plans to evaluate the acreage. In addition, the Company recognized impairment expense of $6.4 million as the result of the Powder River Oil Divestiture as discussed above.
We recognized $207.0 million of proved impairment expense and $2.5 million of unproved property impairment expense during the year ended December 31, 2013 related to our West Tavaputs properties based upon an analysis of the carrying value of the related properties relative to their estimated fair values. These assets were sold in December 2013. In addition, we recognized $17.1 million of impairment expense related to certain unproved oil and gas properties within exploration projects primarily as a result of having no future plans to evaluate the remaining acreage and an estimated market value below our carrying value.
Given the decline in current and future commodity prices, we will continue to review our acreage position and future drilling plans as well as assess the carrying value of our properties relative to their estimated fair values. Lower sustained commodity prices or additional commodity price declines may lead to additional property impairment in future periods.
Loss on Divestitures. Loss on divestitures for the year ended December 31, 2014 consisted of a $79.5 million loss related to the Piceance Divestiture and a $24.5 million loss related to the sale or exchange of the majority of our Powder River Basin assets ("Powder River Oil Divestiture") during the three months ended September 30, 2014, offset by $3.6 million in net gains realized from the sale of other properties. See Note 4 of the Notes to Consolidated Financial Statements for more information related to these divestitures.
Depreciation, Depletion and Amortization. DD&A decreased to $235.8 million for the year ended December 31, 2014 compared with $279.8 million for the year ended December 31, 2013. The decrease of $44.0 million was a result of a 37% decrease in production for the year ended December 31, 2014 compared with the year ended December 31, 2013, partially offset by an increase in the DD&A rate. The decrease in production accounted for a $103.7 million decrease in DD&A expense, while the overall increase in the DD&A rate accounted for $59.7 million of additional DD&A expense.
Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the year ended December 31, 2014, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $25.88 per Boe compared with $19.33 per Boe for the year ended December 31, 2013. The increase in the DD&A rate during the year ended December 31, 2014 was due to an increase in oil development, which has higher capital cost per Boe compared to natural gas development. Future depletion rates will be adjusted to reflect capital expenditures, proved reserve changes and well performance.
Unused Commitments. Unused commitments for the year ended December 31, 2014 were $4.4 million. During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Accordingly, we will continue to incur monthly demand charges of approximately $1.5 million for the remaining term of six years even though we no longer utilizes these contracts. These costs were previously included in gathering, transportation and processing expense in the Consolidated Statements of Operations prior to the completion of the Piceance Divestiture on September 30, 2014.
General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, decreased to $42.0 million for the year ended December 31, 2014 from $49.1 million for the year ended December 31, 2013. The decrease of $7.1 million was primarily the result of a 19% decrease in the number of employees as of December 31, 2014 compared to December 31, 2013, due to our divestitures. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 40 for a reconciliation and explanation. On a per Boe basis, general and administrative expense, excluding non-cash stock-based compensation, increased to $4.61 in 2014 from $3.39 in 2013, primarily related to the 37% decrease in production from 2014 compared with 2013.
Non-cash charges for stock-based compensation for the years ended December 31, 2014 and 2013 were $11.4 million and $15.8 million, respectively. Non-cash stock-based compensation expense for each of the years ended December 31, 2014 and 2013 related primarily to vesting of our stock option awards and nonvested shares of common stock issued to employees.
The components of non-cash stock-based compensation for the years ended December 31, 2014 and 2013 are shown in the following table:
Interest Expense. Interest expense decreased to $69.6 million for the year ended December 31, 2014 from $88.5 million for the year ended December 31, 2013. The decrease for the year ended December 31, 2014 was primarily due to using the proceeds from the West Tavaputs Divestiture and Piceance Divestiture to lower the average debt balance. Our weighted average interest rate for the year ended December 31, 2014 was 6.9% compared with 7.2% for the year ended December 31, 2013.
Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a gain of $197.4 million for the year ended December 31, 2014 compared to a loss of $23.1 million for the year ended December 31, 2013. The gain or loss on commodity derivatives is related to fluctuations of oil, natural gas and NGL future pricing compared to actual pricing of commodity hedges in place as of December 31, 2014 and December 31, 2013.
The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:
Income Tax Benefit. Income tax expense totaled $17.9 million for the year ended December 31, 2014 compared with an income tax benefit of $118.6 million for the year ended December 31, 2013, resulting in effective tax rates of 54.3% and 38.1%, respectively. For both the 2014 and 2013 periods, our effective tax rate differs from the federal statutory rate primarily as a result of recording stock-based compensation expense and other operating expenses that are not deductible for income tax purposes as well as the effect of state income taxes. The effective tax rate change for December 31, 2014 was a result of recording an increase in the beginning deferred balances as a result of an increased state effective rate. At December 31, 2014, we had approximately $168.2 million of federal tax net operating loss carryforwards, or "NOLs", which expire beginning in 2027. We also had a federal alternative minimum tax credit carryforward of $1.7 million, which has no expiration date. We believe it is more likely than not that we will use these tax attributes to offset and reduce tax liabilities in future years. At December 31, 2014, we had approximately $7.9 million of state income tax credit carryforwards. We continue to believe it is more likely than not that this deferred tax asset will not be realized, and therefore a valuation allowance is recorded for the state tax credits.
Year Ended December 31, 2013 Compared with Year Ended December 31, 2012
The following table sets forth selected operating data for the periods indicated:
*
Not meaningful.
(1)
Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense for a total of $64.9 million and $68.7 million for the years ended December 31, 2013 and 2012, respectively, in the Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with stock-based grants.
(2)
Prior to 2013, NGL volumes were included within natural gas production data, which impacts the comparability for the two periods presented.
(3)
Average realized prices shown in the table are net of the effects of all settled commodity hedging transactions related to current period production.
(4)
Natural gas prices for 2012 include the effect of NGL related production and revenue.
(5)
The DD&A per Boe as calculated based on the DD&A expense and production data presented in the table for the year ended December 31, 2012 is $16.67. However, the DD&A rate per Boe for the year ended December 31, 2012 of $17.49, as presented in the table above, excludes fourth quarter production of 911 MBoe, associated with our properties that were sold as of December 31, 2012.
(6)
Excludes non-cash stock-based compensation expense as described in Note 1 above. This presentation is a non-GAAP measure. Average costs per Boe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Consolidated Statements of Operations, were $4.48 and $3.50 for the years ended December 31, 2013 and 2012, respectively.
Production Revenues and Volumes. Production revenues decreased to $565.6 million for the year ended December 31, 2013 from $700.6 million for the year ended December 31, 2012. The decrease in production revenues was primarily due to a 26% decrease in production volumes, offset by an increase in average prices. The decrease in production volumes reduced production revenues by approximately $200.2 million, while the increase in average prices increased production revenues by approximately $65.2 million.
We discontinued hedge accounting as of January 1, 2012. All accumulated gains or losses related to the discontinued cash flow hedges were recorded in accumulated other comprehensive income ("AOCI") as of January 1, 2012 and will remain in AOCI until the underlying transaction occurs. As the underlying transaction occurs, these gains or losses are reclassified from AOCI into oil, gas and NGL production revenues. The amount reclassified to oil, gas and NGL production revenues was a gain of $7.5 million and $81.2 million for the years ended December 31, 2013 and 2012, respectively.
Total production volumes of 14.5 MMBoe for the year ended December 31, 2013 decreased from 19.6 MMBoe for the year ended December 31, 2012. We completed a sale of natural gas assets on December 31, 2012, including 100% of our Wind River Basin and Powder River Basin - Coalbed Methane properties ("PRB-CBM") and an initial 18% interest in the Gibson Gulch assets in the Piceance Basin that progresses to a 26% interest in 2016 (the "2012 Divestiture"). Lower natural gas commodity prices caused us to discontinue drilling activity in the Piceance Basin and West Tavaputs area in the Uinta Basin in 2012 to concentrate on our oil development programs, which has continued to negatively impact 2013 gas production volumes. These decreases were partially offset by a 30% overall increase in oil production with increases in the Uinta Oil Program, DJ Basin and Powder River Oil Program. Additional information concerning production is in the following table:
*
Not meaningful.
(1)
Prior to 2013, NGL volumes were included in natural gas production data, which impacts the comparability for the two periods presented.
(2)
Other for 2012 includes PRB-CBM natural gas volumes of 10,888 MMcf, Wind River natural gas production volumes of 3,913 MMcf and oil production of 18 MBbls.
Hedging Activities. In 2013, approximately 83% of our oil volumes, 92% of our natural gas volumes and 16% of our NGL related volumes were subject to financial hedges, which resulted in a decrease in oil revenues of $0.8 million, partially offset by increases in natural gas revenues of $10.8 million and NGL production revenues of $2.8 million after settlements for all
commodity derivatives. Of the gain on total settlements of $12.8 million for the year ended December 31, 2013, a gain of $7.5 million was included in oil, gas and NGL production revenues and a gain of $5.3 million was included in commodity derivative gain (loss) in the Consolidated Statements of Operations. In 2012, approximately 76% of our oil volumes, 68% of our natural gas volumes (excluding basis only swaps, which were equivalent to 7% of our natural gas volumes), and 23% of our NGL related recoveries were subject to financial hedges, which resulted in an increase in oil revenues of $15.0 million, of which $3.9 million was included in oil, gas and NGL production revenues, and an increase natural gas revenues of $108.5 million, of which $77.2 million was included in oil, gas and NGL production revenues, after settlements for all commodity derivatives, including basis only and NGL swaps.
Other Operating Revenues. Other operating revenues increased to $2.5 million for the year ended December 31, 2013 from a loss of $0.4 million for the year ended December 31, 2012. Other operating revenues for 2013 consisted of $0.2 million in net gains realized from the sale of properties and $2.3 million of income from gathering, compression and salt water disposal fees received from third parties. The net realized gains from the sale of properties for the year ended December 31, 2013 related to a loss of $3.1 million from purchase price adjustments on the 2012 Divestiture, offset by a gain of $3.3 million from selldowns of other properties. Other operating revenues for 2012 consisted of a $4.5 million loss on the sale of our natural gas assets including 100% of our Wind River Basin and Powder River Basin coalbed methane assets, and a non-operating working interest in our Piceance Basin development property. This loss was offset by $2.7 million of income from gathering, compression and salt-water disposal fees received from third parties and $1.4 million from the sale of seismic data.
Lease Operating Expense. Lease operating expense ("LOE") increased to $4.85 per Boe for the year ended December 31, 2013 from $3.71 per Boe for the year ended December 31, 2012. LOE on a per Boe basis is inherently higher from our oil producing properties such as those in our Uinta Oil and DJ Basin development areas. In addition, the 2012 Divestiture consisted of natural gas properties with lower LOE per Boe, which contributed to a higher comparative LOE per Boe unit cost in the year ended December 31, 2013.
Gathering, Transportation and Processing Expense. Gathering, transportation and processing ("GTP") expense decreased to $4.65 per Boe for the year ended December 31, 2013 from $5.44 per Boe for the year ended December 31, 2012. The decrease is primarily due to an increase in oil production for the year ended December 31, 2013, which has lower GTP expense than natural gas as well as the sale of our Powder River- CBM assets as part of the 2012 Divestiture, which had higher GTP expense per Boe compared to our other assets.
Production Tax Expense. Total production taxes increased to $27.2 million for the year ended December 31, 2013 from $25.5 million for the year ended December 31, 2012. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes as a percentage of oil, natural gas and NGL sales before hedging adjustments were 4.9% and 4.1% for the years ended December 31, 2013 and December 31, 2012, respectively.
Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas. The increase in the overall production tax rate is consistent with our production increase in areas with higher production tax rates.
Exploration Expense. Exploration expense for the year ended December 31, 2013 was $0.3 million compared to $8.8 million for the year ended December 31, 2012. Exploration expense for the year ended December 31, 2013 consisted of $0.3 million for delay rentals across all basins. Exploration expense for the year ended December 31, 2012 consisted of $7.9 million of geological and geophysical seismic programs and $0.9 million for delay rentals across all basins.
Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense increased to $238.4 million for the year ended December 31, 2013 from $67.9 million for the year ended December 31, 2012.
For the year ended December 31, 2013, impairment expense was $226.6 million, abandonment expense was $10.7 million and dry hole expense was $1.1 million. The $226.6 million of impairment expense for the year ended December 31, 2013 included $207.0 million related to proved oil and gas properties and $19.6 million related to unproved oil and gas properties. We recognized $207.0 million of proved impairment expense and $2.5 million of unproved property impairment expense during the year ended December 31, 2013 related to our West Tavaputs properties based upon an analysis of the carrying value of the related properties relative to their estimated fair values. These assets were sold in December 2013. In addition, we recognized $17.1 million of impairment expense related to certain unproved oil and gas properties within exploration projects primarily as a result of having no future plans to evaluate the remaining acreage and an estimated market value below our
carrying value. The impairment expense contributed substantially to our net loss of $192.7 million for the year ended December 31, 2013.
For the year ended December 31, 2012, impairment expense was $37.3 million, abandonment expense associated with exploratory drilling locations was $9.6 million and dry hole costs were $21.0 million. The $37.3 million related to impairing certain unproved oil and gas properties within various exploration and development projects primarily as a result of unfavorable market conditions or having no future plans to evaluate the remaining acreage. For the year ended December 31, 2012, we did not record any impairment charges related to proved oil and gas properties.
We evaluate the impairment of our proved oil and gas properties on a property-by-property basis quarterly or whenever events or changes in circumstances indicate a property’s carrying amount may not be recoverable. If the carrying amount exceeds the property’s estimated fair value, we will adjust the carrying amount of the property to fair value through a charge to impairment expense.
Unproved oil and gas properties are also assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop existing acreage. We continue to review our acreage position and future drilling plans based on the current price environment. If our attempts to market interests in certain properties to industry partners are unsuccessful, we may record additional leasehold impairments and abandonments in exploration prospects.
Dry hole costs of $1.1 million for the year ended December 31, 2013 primarily relate to additional costs on wells deemed to be dry holes in 2012. Dry hole costs of $21.0 million for the year ended December 31, 2012 primarily relate to two unsuccessful exploratory natural gas wells in the Paradox Basin and one unsuccessful exploratory well in the Alberta Basin.
Depreciation, Depletion and Amortization. DD&A decreased to $279.8 million for the year ended December 31, 2013 compared with $326.8 million for the year ended December 31, 2012. The decrease of $47.0 million was a result of a 26% decrease in production for the year ended December 31, 2013 compared with the year ended December 31, 2012, offset by an increase in the DD&A rate. The decrease in production accounted for a $89.6 million decrease in DD&A expense, while the overall increase in the DD&A rate accounted for $42.6 million of additional DD&A expense. The increase in the DD&A rate during the year ended December 31, 2013 was due to an increase in the mix of oil projects in 2013 as compared to 2012, as oil projects have higher capital costs per reserve unit compared to natural gas projects, and the sale of properties with lower DD&A rates in the 2012 Divestiture.
Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field to determine a depletion rate for current production. For the year ended December 31, 2013, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $19.33 per Boe compared with $17.49 per Boe for the year ended December 31, 2012. Future depletion rates will be adjusted to reflect capital expenditures, proved reserve changes and well performance.
General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, decreased to $49.1 million for the year ended December 31, 2013 from $52.2 million for the year ended December 31, 2012. The decrease of $3.1 million was primarily the result of a 26% decrease in the number of employees as of December 31, 2013 compared to December 31, 2012, due to the Company's divestitures. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 46 for a reconciliation and explanation. On a per Boe basis, general and administrative expense, excluding non-cash stock-based compensation, increased to $3.39 in 2013 from $2.66 in 2012, primarily related to the 26% decrease in production from 2013 compared with 2012.
Non-cash charges for stock-based compensation for the years ended December 31, 2013 and 2012 were $15.8 million and $16.4 million, respectively. Non-cash stock-based compensation expense for each of the years ended December 31, 2013 and 2012 related primarily to vesting of our stock option awards and nonvested shares of common stock issued to employees.
The components of non-cash stock-based compensation for the years ended December 31, 2013 and 2012 are shown in the following table:
Interest Expense. Interest expense decreased to $88.5 million for the year ended December 31, 2013 from $95.5 million for the year ended December 31, 2012. The decrease for the year ended December 31, 2013 was primarily due to a lower weighted average interest rate as a result of the redemption of our 9.875% Senior Notes on July 15, 2013. Our weighted average interest rate for the year ended December 31, 2013 was 7.2% compared with 8.2% for the year ended December 31, 2012.
Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a loss of $23.1 million for the year ended December 31, 2013 compared to a gain of $72.8 million for the year ended December 31, 2012. The decrease was primarily due to a decrease in our natural gas hedging contracts as a result of lower natural gas volumes hedged and a large increase in oil futures pricing for the year ended December 31, 2013 compared with December 31, 2012.
The table below summarizes the Company's commodity derivative gains and losses that were recognized in the periods presented:
Income Tax Benefit. Income tax benefit totaled $118.6 million for the year ended December 31, 2013 compared with an income tax expense of $1.6 million for the year ended December 31, 2012, resulting in effective tax rates of 38.1% and 73.8%, respectively. For both the 2013 and 2012 periods, our effective tax rate differs from the federal statutory rate primarily as a result of recording stock-based compensation expense and other operating expenses that are not deductible for income tax purposes as well as the effect of state income taxes. The effective tax rate for December 31, 2012 was exceptionally high due to the amount of non-deductible expenses relative to the low operating income coupled with the effect a statutory rate increase had on the Company’s prior year net deferred tax liability. At December 31, 2013, we had approximately $218.0 million of federal tax net operating loss carryforwards, or "NOLs", which expire through 2033. We also had a federal alternative minimum tax credit carryforward of $0.7 million, which has no expiration date. We believe it is more likely than not that we will use these tax attributes to offset and reduce tax liabilities in future years. At December 31, 2013, the Company had approximately $5.9 million of state income tax credit carryforwards. We continue to believe it is more likely than not that this deferred tax asset will not be realized, and therefore a valuation allowance is recorded for the state tax credits.
Capital Resources and Liquidity
Our primary sources of liquidity since our formation in January 2002 have been net cash provided by operating activities, sales and other issuances of equity and debt securities, notes and senior notes, bank credit facilities, proceeds from sale-leasebacks, joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources, including potential issuances of equity and debt securities, available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. We believe that we have significant liquidity available to us from cash flows from operations and under our Amended Credit Facility for our planned uses of capital. However, we expect to pursue opportunities to further improve our liquidity position through capital markets or other transactions if we believe conditions to be favorable.
At December 31, 2014, we had cash and cash equivalents of $165.9 million and no amounts outstanding under our Amended Credit Facility. Our borrowing base is dependent on our proved reserves and hedge position and as of December 31, 2014 was $375.0 million. Our borrowing capacity was reduced by $26.0 million to $349.0 million as of December 31, 2014 due to an outstanding irrevocable letter of credit related to a firm transportation agreement.
Cash Flow from Operating Activities
Net cash provided by operating activities was $261.7 million, $265.3 million and $388.4 million in 2014, 2013 and 2012, respectively. The changes in net cash provided by operating activities are discussed above in "Results of Operations". The decrease in net cash provided by operating activities for the years ended December 31, 2014 and 2013 compared to 2012 was largely due to our asset sales and the related 37% and 26% decreases in production volumes in 2014 and 2013, respectively. In addition, operating costs decreased for the years ended December 31, 2014 and 2013, which partially offset the decrease in operating cash flows due to lower production volumes.
Commodity Hedging Activities
Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.
To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap contracts to receive fixed prices for a portion of our production revenue. At December 31, 2014, we had in place crude oil swaps covering portions of our 2015, 2016 and 2017 production and natural gas swaps covering portions of our 2015 and 2016 production.
In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of oil, natural gas and NGLs that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil, gas and NGL production revenues at the time of settlement.
All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value and are included in the Consolidated Balance Sheets as assets or liabilities. All fair values are adjusted for non-performance risk. All changes in the derivative’s fair value are recorded in earnings. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the associated derivative instrument contract is settled by making a payment to or receiving a payment from the counterparty.
At December 31, 2014, the estimated fair value of all of our commodity derivative instruments was a net asset of $195.0 million, comprised of current and long-term assets.
The table below summarizes the realized and unrealized gains and losses that we recognized related to our oil, natural gas and NGL derivative instruments for the periods indicated:
(1)
Included in oil, gas and NGL production revenues in the Consolidated Statements of Operations.
(2)
Included in commodity derivative gain (loss) in the Consolidated Statements of Operations.
(3)
Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.
The following table summarizes all of our hedges in place as of December 31, 2014:
By removing the price volatility from a portion of our oil related revenue for 2015, 2016 and 2017, and natural gas related revenue for 2015 and 2016, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.
It is our policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility or potential lenders in the Amended Credit Facility. Our derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. ("ISDA") Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. We are not required to provide any credit support to our counterparties other than cross collateralization with the properties securing the Amended Credit Facility. We have set-off provisions in our derivative contracts with lenders under our Amended Credit Facility which, in the event of a counterparty default, allow us to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed us under derivative contracts. Where the counterparty is not a lender under the Amended Credit Facility, we may not be able to set-off amounts owed by us under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility.
Capital Expenditures
Our capital expenditures are summarized in the following tables for the periods indicated:
(1)
Capital expenditures for the year ended December 31, 2014 exclude $79.0 million related to property acquired through property exchanges.
(2)
For the years ended December 31, 2014, 2013 and 2012, we received $555.4 million, $306.3 million and $325.3 million, respectively, of proceeds principally from the sale of interests in oil and gas properties, which are not deducted from the capital expenditures presented above.
(3)
Excludes future reclamation liabilities of negative $8.6 million, negative $6.6 million and $7.5 million for the years ended December 31, 2014, 2013 and 2012, respectively, and includes exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of $7.2 million, $12.2 million and $39.3 million for the years ended December 31, 2014, 2013 and 2012, respectively.
(4)
Includes related gathering and facilities costs.
Capital expenditures for acquisitions of proved and unproved properties and other real estate were $15.1 million for the year ended December 31, 2014. This was primarily related to acquisitions of unproved properties in the DJ and Uinta Basins. The increase in drilling, development, exploration and exploitation of oil and natural gas properties to $550.0 million for the year ended December 31, 2014 from $456.2 million for the year ended December 31, 2013 primarily related to an increase in development drilling and completion activities within the DJ Basin.
Capital expenditures for acquisitions of proved and unproved properties and other real estate were $16.2 million for the year ended December 31, 2013. This was primarily related to our acquisitions of proved and unproved properties in the DJ, Powder River and Uinta Basins. The decrease in drilling, development, exploration and exploitation of oil and natural gas properties to $456.2 million from $778.4 million for the year ended December 31, 2012 related to a decrease in development drilling and completion activities in the Uinta and Piceance Basins.
Our current estimated capital expenditure budget in 2015 is $240.0 million to $280.0 million, with all drilling activities targeting oil. The budget includes facilities costs and excludes acquisitions. We may adjust capital expenditures throughout the year as business conditions and operating results warrant. The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If oil, natural gas and NGL prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity generally by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near-term cash flow. We routinely monitor and adjust our capital expenditures, including acquisitions and divestitures, in response to changes in prices and other economic and market conditions, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside of our control.
We believe that we have sufficient available liquidity with available cash under the Amended Credit Facility and cash flow from operations to fund our 2015 budgeted capital expenditures. Future cash flows are subject to a number of variables, including our level of oil and natural gas production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of capital expenditures.
Financing Activities
Amended Credit Facility. Our Amended Credit Facility has a maturity date of October 31, 2016 and current commitments and borrowing base of $375.0 million. As of December 31, 2014, we had no amounts outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit has been issued under the Amended Credit Facility, which reduces the current available borrowing capacity of the Amended Credit Facility to $349.0 million.
Interest rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the commitment fee is between 0.375% to 0.5% based on borrowing base utilization. The average annual interest rates incurred on the Amended Credit Facility were 1.9% and 2.0% for the years ended December 31, 2014 and 2013, respectively.
The borrowing base is required to be re-determined twice per year, on or about April 1 and October 1. On September 30, 2014, the borrowing base was reduced to $375.0 million based on our June 30, 2014 proved reserves, as adjusted for the Piceance and Powder River Oil Divestitures and our hedge position. Future semi-annual borrowing bases will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt of the Company.
The Amended Credit Facility is secured by oil and natural gas properties representing at least 80% of the value of our proved reserves and the pledge of all of the stock of our subsidiaries. The Amended Credit Facility contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance.
5% Convertible Senior Notes Due 2028. On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012, $147.2 million of the outstanding principal amount, or approximately 85% of the outstanding Convertible Notes, were put to us and redeemed by us at par. We settled the notes in cash. After the redemption, $25.3 million aggregate principal amount of the Convertible Notes was outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by us. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of the Company’s existing and future senior unsecured indebtedness, are senior in right of payment to all of our future subordinated indebtedness, and are effectively subordinated to all of our secured indebtedness with respect to the collateral securing such indebtedness. The Convertible Notes are structurally subordinated to all present and future secured and unsecured debt and other obligations of our subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the 7.625% Senior Notes and the 7.0% Senior Notes.
The Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year. Holders of the remaining Convertible Notes may require us to purchase all or a portion of their Convertible Notes for cash on each of March 20, 2015, March 20, 2018 and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. We have the right, with at least 30 days’ notice, to call the Convertible Notes. The Company classified the Convertible Notes as a current obligation on the Consolidated Balance Sheets as of December 31, 2014 as the holders may require us to purchase their Convertible Notes for cash on March 20, 2015.
7.625% Senior Notes Due 2019. On September 27, 2011, we issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. The 7.625% Senior Notes mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 of each year. The 7.625% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.0% Senior Notes. The 7.625% Senior Notes are redeemable on October 1, 2015 at our option at a redemption price of 103.813% of the principal amount of the notes. The 7.625% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.0% Senior Notes. The 7.625% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create
liens or sell assets and that prohibit us from paying dividends. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance.
7.0% Senior Notes Due 2022. On March 12, 2012, we issued $400.0 million in aggregate principal amount of 7.0% Senior Notes due 2022 at par. The 7.0% Senior Notes mature on October 15, 2022. Interest is payable in arrears semi-annually on April 15 and October 15 of each year. The 7.0% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.625% Senior Notes. The 7.0% Senior Notes are redeemable at our option on October 15, 2017 at a redemption price of 103.5% of the principal amount of the notes. The 7.0% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee the Amended Credit Facility, the Convertible Notes and the 7.625% Senior Notes. The 7.0% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that prohibit us from paying dividends. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance.
Lease Financing Obligation Due 2020. On July 23, 2012, we entered into a lease financing arrangement with Bank of America Leasing & Capital, LLC as the lead bank (the "Lease Financing Obligation") whereby we received $100.8 million through the sale and subsequent leaseback of existing compressors and related facilities owned by us. The Lease Financing Obligation expires on August 10, 2020, and we have the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligation also contains an early buyout option where we may purchase the equipment on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.3%. As the result of the disposition of equipment in the West Tavaputs Divestiture and the Piceance Divestiture, our remaining Lease Financing Obligation has been reduced to $3.6 million as of December 31, 2014 and the early buyout option is reduced to $1.8 million.
Our outstanding debt is summarized below:
(1)
The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure.
(2)
The aggregate estimated fair value of the Convertible Notes was approximately $25.1 million as of December 31, 2014 and 2013, based on reported market trades of these instruments.
(3)
We have the right at any time with at least 30 days’ notice to call the Convertible Notes, and the holders have the right to require us to purchase the notes on each of March 20, 2015, March 20, 2018 and March 20, 2023.
(4)
The aggregate estimated fair value of the 7.625% Senior Notes was approximately $359.8 million and $430.2 million as of December 31, 2014 and 2013, respectively, based on reported market trades of these instruments.
(5)
The aggregate estimated fair value of the 7.0% Senior Notes was approximately $366.0 million and $417.0 million as of December 31, 2014 and 2013, respectively, based on reported market trades of these instruments.
(6)
The aggregate estimated fair value of the Lease Financing Obligation was approximately $3.5 million and $41.7 million as of December 31, 2014 and 2013, respectively. The decrease in estimated fair value is primarily related to the sale of equipment in the West Tavaputs and Piceance Divestitures. Because there is no active, public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.
(7)
The current portion of long-term debt as of December 31, 2014 includes the current portion of the Lease Financing Obligation and the principal amount of the Convertible Notes. The Company classified the Convertible Notes as a current obligation as the holders may require us to purchase their Convertible Notes for cash on March 20, 2015.
(8)
The current portion of long-term debt as of December 31, 2013 includes the current portion of the Lease Financing Obligation.
Credit Ratings. Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. Moody’s Investor Services and Standard & Poor’s Rating Services currently rate our 7.625% Senior Notes and 7.0% Senior Notes and have assigned a credit rating. We do not have any provisions that are linked to our credit ratings, nor do we have any credit rating triggers that would accelerate the maturity of amounts due under our Amended Credit Facility, the Convertible Notes, the 7.625% Senior Notes or the 7.0% Senior Notes. However, our ability to raise funds and the costs of any financing activities will be affected by our credit rating at the time any such financing activities are conducted.
Contractual Obligations. A summary of our contractual obligations as of and subsequent to December 31, 2014 is provided in the following table:
(1)
Included in notes payable is a $26.0 million letter of credit that accrues interest at 2.0% and 0.125% per annum for participation fees and fronting fees, respectively. The expected term for the letter of credit is April 30, 2018. There is currently no balance outstanding under our Amended Credit Facility due October 31, 2016.
(2)
On September 27, 2011, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes. We are obligated to make annual interest payments through maturity in 2019 equal to $30.5 million.
(3)
On March 25, 2012, we issued $400.0 million aggregate principal amount of 7.0% Senior Notes. We are obligated to make annual interest payments through maturity in 2022 equal to $28.0 million.
(4)
On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012 approximately 85% of the outstanding Convertible Notes, representing $147.2 million of the then outstanding principal amount, were put to us. We settled the notes in cash and recognized a gain on extinguishment of $1.6 million after completing a fair value analysis of the consideration transferred to holders of the Convertible Notes. After the redemption in March 2012, $25.3 million principal amount of the Convertible Notes is currently outstanding. We are obligated to make semi-annual interest payments on the Convertible Notes until either we call the remaining Convertible Notes or the holders put the Convertible Notes to us. The Company classified the Convertible Notes as a current obligation on the Consolidated Balance Sheets as of December 31, 2014 as the holders may require us to purchase their Convertible Notes for cash on March 20, 2015.
(5)
The Lease Financing Obligation is calculated based on the aggregate undiscounted minimum future lease payments, which include both an interest and principal component.
(6)
We have one take-or-pay carbon dioxide purchase agreement that expires in December 2015. The agreement imposes a minimum volume commitment ("MVC") to purchase CO2 at a contracted price. The contract provides CO2 used in fracture stimulation operations. If we do not take delivery of the minimum volume required, we are obligated to pay for the deficiency. As of December 31, 2014, $1.7 million of the future commitment is due by December 31, 2015.
(7)
The values in the table represent the gross amounts that we are financially committed to pay. However, we will record in our financial statements our proportionate share based on our working interest and net revenue interest, which will vary from property to property.
(8)
The lease for our principal offices in Denver extends through March 2019.
(9)
Includes a sales throughput contract in the South Altamont area of the Uinta Oil Basin. Under this contract, we are obligated to sell and deliver a MVC of 450.0 MMcf for the period of December 1, 2014 to November 30, 2015. If the minimum volume is not delivered, we must make a deficiency payment of up to $0.8 million. As of December 31, 2014, we have satisfied approximately 19.3 MMcf of this commitment, resulting in an estimated deficiency payment of up to $0.7 million due December 1, 2015.
(10)
We have entered into contracts that provide firm transportation capacity on pipeline systems. The remaining term on these contracts is six years. The contracts require us to pay transportation demand charges regardless of the amount of gas we deliver to the pipeline.
(11)
Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See "Critical Accounting Policies and Estimates" below for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.
Trends and Uncertainties
Regulatory Trends
Our future Rockies operations and cost of doing business may be affected by changes in regulations and the ability to obtain drilling permits. The regulatory environment continues to become more restrictive, which limits our ability to, and increases the costs of conducting our operations. Areas in which we operate are subject to federal, state, local and tribal regulations. Additional and more restrictive regulations have been seen at each of these governmental levels recently and there are initiatives underway to implement additional regulations and prohibitions on oil and gas activities. New rules may further impact our ability to obtain drilling permits and other required approvals in a timely manner and/or increase the costs of such permits or approvals. This may create substantial uncertainty about our production and capital expenditure targets.
Federal. Federal leases make up approximately 25% of our leaseholds. At the federal level, the policies of the current administration and the Department of the Interior have resulted in a more restrictive regulatory environment for oil and gas activities on public lands. The Secretary of Interior has issued policy directives that require additional analysis prior to leasing federal lands. These policies are directed at reducing controversy and improving predictability of the leasing process. We believe that until these policies are implemented and the requisite analyses are completed, the rate of federal leasing will decrease. The Bureau of Land Management ("BLM") and the U.S. Forest Service also have withdrawn parcels from planned lease sales in areas near our operations. A lawsuit seeks review of federal resource management plans prepared by the BLM for areas of Utah, including areas in which we operate. If this challenge is successful, it could impact our ability to operate and to obtain additional leases in the area. Additional litigation seeking to halt our and other companies’ exploration and development activities throughout the Rockies can be expected. Proposals to cause expiration of undeveloped leases, to further limit funding for processing of federal drilling permits and to eliminate categorical exclusions for oil and gas activities have been reintroduced.
State. We also are experiencing increased attempts to more strictly regulate oil and gas activities at the state level. For example, several statewide ballot initiatives were proposed in early 2014 that would have restricted or limited oil and natural gas development in Colorado, notably by amending the Colorado constitution (i) to impose a 2,000 foot statewide drilling setback from occupied structures and (ii) to establish an environmental bill of rights increasing local government authority to enact environmental regulations that are more restrictive than those adopted by the state government. Proponents of these initiatives withdrew them in August 2014 under a political compromise reached with Colorado Governor John Hickenlooper. Under the compromise, the Governor appointed a 21 member oil and gas task force (the "Task Force") by Executive Order, directing it to examine a range of issues and policy options to respond to the public concerns inherent in the withdrawn ballot initiatives. The Task Force is to make its report to the Governor and the Colorado General Assembly by March 2015. The outcome of this Task Force process is unclear, especially considering the potential impact of the 2014 gubernatorial and legislative elections. It is possible, however, that recommendations could be made, and subsequently adopted by legislation or regulation, that might impede our planned drilling activities in Colorado, including increasing regulatory and operational costs.
In addition, new rules and policies have been imposed by the COGCC requiring disclosure of chemicals used in hydraulic fracturing, ground water monitoring, setbacks from occupied structures and existing wells, and most recently amendments to COGCC’s enforcement policies, including increases in mandatory monetary penalties for certain violations. As discussed in "Items 1 and 2. Business and Properties - Operations - Environmental Matters and Regulation", Colorado regulators also promulgated new, statewide air emissions regulations in 2014 that are more stringent than federal requirements. Colorado continues to look at air emissions from the oil and natural gas sector and additional regulations in this respect are possible. Other states, and the EPA, have considered Colorado’s air quality rules, including the most recent rules governing methane emissions, as potential models for additional regulation of the oil and natural gas sector. Several states also have proposed
severance tax increases. These new state rules and policies could impose additional costs on our operations, delay permitting, and potentially impact profitability.
Local. Counties and municipalities regulate oil and gas activities primarily through local land use rules. Most counties and municipalities where we operate require special use permits for activities that previously were regulated by the states, adding new requirements and delays over previous operations. We expect additional attempts to regulate activities related to oil and gas operations by local governments, including potential moratoria or bans on hydraulic fracturing. For example, in Colorado, several municipalities have approved bans of varying length on hydraulic fracturing within their respective jurisdictions. Litigation is pending on the legality of these Colorado bans, but local governments in other states have enacted or considered enacting similar bans.
Tribal. We have experienced delays in obtaining permits to drill wells and access and rights of way agreements on tribal property, including our Lake Canyon and Black Tail Ridge projects. The failure to obtain permits has led us to declare a force majeure event in order to protect our rights under our Black Tail Ridge exploration and development agreement. Because of the current staffing of the permitting authorities, we believe that delays in obtaining permits will continue for the foreseeable future, which will delay our ability to drill wells in these areas.
Hydraulic Fracturing. The well completion technique known as hydraulic fracturing to stimulate production of natural gas and oil has come under increased scrutiny by the environmental community, and local, state, and federal jurisdictions. Hydraulic fracturing involves the injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate oil and natural gas production. We use this completion technique on substantially all our wells. A more comprehensive discussion of potential risks and trends related to hydraulic fracturing is contained above in Item 1A Risk Factors. Although it is not possible at this time to predict the final outcome of any proposed legislation, or potential regulatory or policy developments regarding hydraulic fracturing, any new restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions and could lead to our inability to access, develop, and record natural gas and oil reserves in the future.
Air Quality Regulation. The regulation of air emissions from the oil and natural gas sector continues to be a significant focus for policy makers, regulators at all levels-federal, tribal, state, and local-as well as environmental groups. A more comprehensive discussion of government regulation and potential risks related to air emissions from our operations is included above in "Items 1 and 2. Business and Properties - Operations - Environmental Matters and Regulation". New or more stringent policies, rules, or regulations governing air emissions from the oil and natural gas sector could result in our inability to obtain permits necessary to construct and operate new facilities or operate existing facilities. In addition, even if we are able to obtain necessary permits, such new requirements could substantially increase our operating expenses and reduce our profits or make certain operations uneconomic.
Potential Impacts of Regulatory Trends. The increase in regulatory burdens and potential for continued lawsuits seeking to block activities as described above is likely to cause delays to our planned activities and could prevent some of these activities. This is expected to increase our costs and could result in lower production and reserves as our properties naturally decline without replacement production and reserves from new wells in addition to a reduction in the value of our current leases.
For additional detail, see "Items 1 and 2. Business and Properties - Operations - Environmental Matters and Regulation" and "Items 1 and 2. Business and Properties - Business - Operations - Other Regulation of the Oil and Gas Industry".
Declining Commodity Prices. The severe decline in oil prices that occurred late in 2014, which has continued into 2015, has increased the volatility and amplitude of the other risks facing us as described in this report and has impacted our unit price and may have an impact on our business and financial condition. If oil prices remain low for an extended period of time, drilling in our DJ and Uinta Oil projects may become uneconomic, which could affect future drilling plans and growth rates. Low commodity prices impact our revenue, which we partially mitigate with our hedging program. We currently have hedged approximately 90% of our expected 2015 production and 40% of our expected 2016 production at price levels that provide some economic certainty to our capital investments. Continued low commodity prices make it more challenging to hedge production at higher price levels. Lower sustained commodity prices or additional commodity price declines may lead to property impairment in future periods.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 of the Notes to the Consolidated Financial Statements for a discussion of additional accounting policies and estimates made by management.
Oil and Gas Properties
Our oil, natural gas and NGL exploration, development and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the property has proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and remain within cash flows from investing activities in the Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether productive or nonproductive. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well, and we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Oil and gas lease acquisition costs are also capitalized. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use.
The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. In addition to development on exploratory wells, we may drill scientific wells that are only used for data gathering purposes. The costs associated with these scientific wells are expensed as incurred as exploration expense. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and industry experience.
Other exploration costs, including certain geological and geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production depletion rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.
Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unproved oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage and other relevant matters. We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities. We continue to review our acreage position and future drilling plans based on the current price environment. If our attempts to market interests in certain properties to industry partners are unsuccessful, we may record additional leasehold impairments.
We review our proved oil and natural gas properties for impairment on an annual basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and gas properties and compare these undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present
value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk associated with realizing the projected cash flows.
Given the decline in current and estimated future commodity prices, we will continue to review our acreage position and future drilling plans as well as assess the carrying value of our properties relative to their estimated fair values. Lower sustained commodity prices or additional commodity price declines may lead to impairment in future periods.
The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in anticipation of finding a gas and oil field that will be the focus of future development drilling activity. If initial exploratory wells are unsuccessful, they are expensed. Seismic costs can be substantial, which will result in additional exploration expenses when incurred.
Our investment in oil and natural gas properties includes an estimate of the future costs associated with dismantlement, abandonment and restoration of our properties. The present value of the estimated future costs to dismantle, abandon and restore a well location are added to the capitalized costs of our oil and gas properties and recorded as a long-term liability. The capitalized cost is included in the oil and natural gas property costs that are depleted over the life of the assets.
The recognition of an asset retirement obligation ("ARO") requires that management make numerous estimates, assumptions and judgments regarding such factors as amounts, future advances in technology, timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. In periods subsequent to initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors and changes to our credit-adjusted risk-free rate as market conditions warrant. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis and an adjustment in our DD&A expense in future periods.
The provision for depletion of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas is converted to barrel of oil equivalents, Boe, at the standard rate of six Mcf to one barrel. Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which incorporate assumptions regarding future development and abandonment costs as well as our level of capital spending. If the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income. This decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.
Oil and Gas Reserve Quantities
Our estimate of proved reserves is based on the quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. Our proved reserves estimates are audited on a well-by-well basis by an independent third party engineering firm. In the aggregate, the independent third party petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates as of December 31, 2014.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserves estimates. We prepare our reserves estimates, and the projected cash flows derived from these reserves estimates, in accordance with SEC guidelines. Our independent third party engineering firm adheres to the same guidelines when auditing our reserve reports. The accuracy of our reserves estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the reserves estimates.
The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continued reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserves estimates represent the most accurate assessments possible, the subjective decisions and variances in available data for various
fields make these estimates generally less precise than other estimates included in our financial statements. As such, reserves estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.
Please refer to the reserve disclosures in "Items 1 and 2 - Business and Properties" for further detail on reserves data.
Revenue Recognition
We record revenues from the sales of oil, natural gas and NGLs in the month that delivery to the purchaser has occurred and title has transferred. We receive payment from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. Historically, any differences have been insignificant.
Derivative Instruments and Hedging Activities
We use derivative financial instruments to achieve a more predictable cash flow from our oil, natural gas and NGLs production by reducing our exposure to price fluctuations. These derivative instruments are recorded at fair market value and included in the balance sheet as assets or liabilities.
Effective January 1, 2012, we elected to discontinue hedge accounting prospectively. Consequently, as of January 1, 2012, we no longer designate any hedges as cash flow hedges and we elected to de-designate all commodity hedge instruments that were previously designated as cash flow hedges as of December 31, 2011. The election to de-designate commodity hedges did not impact our reported cash flows, did not affect the economic substance of these transactions and changed only how these transactions were reported in the Consolidated Financial Statements. As a result of discontinuing hedge accounting effective January 1, 2012, the mark-to-market value of all commodity hedge instruments within accumulated other comprehensive income ("AOCI") at December 31, 2011 was frozen in AOCI as of the de-designation date and was reclassified into earnings in future periods as the original hedged transactions occurred. All cash flow hedged transactions were completed by December 31, 2014.
The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Before discontinuing cash flow hedge accounting effective January 1, 2012, we were required to formally document, at the inception of a hedge, the hedging relationship and the risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.
For derivative instruments that were designated as cash flow hedges, changes in fair value, to the extent the hedge was effective, were recognized in AOCI until the hedged item was recognized in earnings. Hedge effectiveness was assessed quarterly based on total changes in the derivatives’ fair value. Any ineffective portion of the derivative instrument’s change in fair value was recognized immediately in earnings.
Currently, our financial derivative instruments are marked to market with the resulting changes in fair value recorded in earnings. As a result of our election to discontinue cash flow hedge accounting effective January 1, 2012, we reclassified the commodity derivative gain (loss) line item within the Consolidated Statements of Operations from operating and other revenues to other income and expenses, due to the change in the composition of the commodity derivative gain (loss) line item, to include prospective fair value changes of hedge instruments.
The estimates of the fair values of our derivative instruments require substantial judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
Income Taxes and Uncertain Tax Positions
Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statement and income tax reporting.
We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider estimated future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). There can be no assurance that facts and circumstances will not materially change and require us to establish deferred tax asset valuation allowances in a future period.
Accounting guidance for recognizing and measuring uncertain tax positions prescribes a more likely than not recognition threshold that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. Based on this guidance, we regularly analyze tax positions taken or expected to be taken in a tax return based on the threshold prescribed. Tax positions that do not meet or exceed this threshold are considered uncertain tax positions. Penalties, if any, related to uncertain tax positions would be recorded in other expenses. We currently do not have any uncertain tax positions recorded as of December 31, 2014.
We are subject to taxation in many jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions. If we ultimately determine that the payment of these liabilities will be unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine the liability no longer applies. Conversely, we record additional tax charges in a period in which we determine that a recorded tax liability is less than we expect the ultimate assessment to be.
Stock-Based Compensation
We recognize compensation expense for all share-based payment awards made to employees and directors. Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the requisite service period, which is generally the vesting period. Judgments and estimates are made regarding, among other things, the appropriate valuation methodology to follow in valuing stock compensation awards and the related inputs required by those valuation methodologies. The Black-Scholes option-pricing model uses assumptions regarding expected volatility of our common stock, the risk-free interest rates, expected term of the awards and other valuation inputs, which are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized. The Monte Carlo simulation method uses assumptions regarding random projections and must be repeated numerous times to achieve a probable assessment. Any change in inputs or number of inputs to this calculation could impact the valuation and thus the stock-based compensation expense recognized.
We recorded non-cash stock-based compensation expense of $11.0 million, $15.6 million and $16.4 million for the years ended December 31, 2014, 2013 and 2012, respectively, for option grants, option modifications, nonvested equity shares of common stock, nonvested equity shares of common stock units, and nonvested performance-based equity shares of common stock.
New Accounting Pronouncements
In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The objective of this update is to provide guidance in GAAP about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The standard will be adopted prospectively.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the potential impact that the adoption will have on the Company’s disclosures and financial statements.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we
view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our primary market risk exposure is in the prices we receive for our production. Commodity pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. For example, the West Texas Intermediate price per Bbl as quoted on the NYMEX was $98.42 per Bbl at December 31, 2013 compared to $53.27 at December 31, 2014. The prices we receive for future production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our derivative contracts in place for the year ended December 31, 2014, our annual revenues would have decreased by approximately $0.2 million for each $1.00 per barrel decrease in crude oil prices, $0.3 million for each $0.10 decrease per MMBtu in natural gas prices and $1.1 million for each $1.00 per barrel decrease in NGL prices. We are more susceptible to proved and unproved property impairments due to the current commodity price environment.
We routinely enter into commodity hedges relating to a portion of our projected production revenue through various financial transactions that hedge future prices received. These transactions may include financial price swaps whereby we will receive a fixed price and pay a variable market price to the contract counterparty. These commodity hedging activities are intended to support oil, natural gas and NGL prices at targeted levels that provide an acceptable rate of return and to manage our exposure to oil, natural gas and NGL price fluctuations.
As of January 27, 2015, we have financial derivative instruments related to oil, natural gas and NGL volumes in place for the following periods indicated. Further detail of these hedges is summarized in the table presented under "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations- Capital Resources and Liquidity- Commodity Hedging Activities".
Interest Rate Risks
At December 31, 2014, we had no amounts outstanding under our Amended Credit Facility, which bears interest at floating rates. The average annual interest rate incurred on this debt for the year ended December 31, 2014 was 1.9%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the year ended December 31, 2014 would have resulted in an estimated $1.6 million increase in interest expense assuming a similar average debt level to the year ended December 31, 2014. The average annual interest rate incurred on this debt for the year ended December 31, 2013 was 2.0%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the year ended December 31, 2013 would have resulted in an estimated $1.8 million increase in interest expense assuming a similar average debt level to the year ended December 31, 2013. We also had $25.3 million principal amount of Convertible Notes (with a fixed cash interest rate of 5%), $400.0 million principal amount of 7.625% Senior Notes, $400.0 million principal amount of 7.0% Senior Notes and $3.6 million principal amount of 3.3% Lease Financing Obligation outstanding at December 31, 2014.
Item 8.
Item 8.
Financial Statements and Supplementary Data.
The information required by this item is included below in "Item 15. Exhibits, Financial Statement Schedules".
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A.
Controls and Procedures.
Evaluation of Disclosure Controls and Procedures. As of December 31, 2014, we carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the "Exchange Act"). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of December 31, 2014.
Management’s Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining internal control over financial reporting. Our internal control over financial reporting is a process designed under the supervision of the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Management assessed the effectiveness of our internal control over financial reporting. In making this assessment, it used the criteria set forth by the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment we have concluded that, as of December 31, 2014, our internal control over financial reporting is effective.
Our independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. That report is set forth below.
Changes in Internal Controls. There has been no change in our internal control over financial reporting during the fourth fiscal quarter of 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Bill Barrett Corporation
Denver, Colorado
We have audited the internal control over financial reporting of Bill Barrett Corporation and subsidiaries (the "Company") as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014 of the Company and our report dated February 26, 2015 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Denver, Colorado
February 26, 2015
Item 9B.
Item 9B.
Other Information.
None.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance.
The information required by this item will be included in an amendment to this Form 10-K or in the "Directors and Executive Officers" section, the "Section 16(a) Beneficial Ownership Reporting Compliance" section, the "Code of Business Conduct and Ethics" section and the "Corporate Governance" section of the proxy statement for the 2015 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2014, and is incorporated by reference to this report.
The information required by this item will be included in an amendment to this Form 10-K or in the "Executive Compensation" section and the "Director Compensation" section of the proxy statement for the 2015 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2014, and is incorporated by reference to this report.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Information regarding beneficial ownership will be included in an amendment to this Form 10-K or in the "Beneficial Owners of Securities" section of the proxy statement for the 2015 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2014, and is incorporated by reference to this report.
Equity Compensation Plan Information
The following table provides aggregate information presented as of December 31, 2014 with respect to all compensation plans under which equity securities are authorized for issuance.
(1)
The weighted average exercise price relates to the 1,339,365 outstanding options included in column (a).
Item 13.
Item 13.
Certain Relationships and Related Transactions and Director Independence.
The information required by this item will be included in an amendment to this Form 10-K or in the "Approval of Related Party Transactions" section and the "Corporate Governance" section of the proxy statement for the 2015 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2014, and is incorporated by reference to this report.
Item 14.
Item 14.
Principal Accounting Fees and Services.
The information required by this item will be included in an amendment to this Form 10-K or in the "Fees to Independent Auditors" section of the proxy statement for the 2015 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2014, and is incorporated by reference to this report.
PART IV
Item 15.
Item 15.
Exhibits, Financial Statement Schedules.
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules.
All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto.
(a)(3) Exhibits.
*
Indicates a management contract or compensatory plan or arrangement, as required by Item 15(a)(3).
**
Filed herewith.
***
Furnished herewith.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Bill Barrett Corporation
Denver, Colorado
We have audited the accompanying consolidated balance sheets of Bill Barrett Corporation and subsidiaries (the "Company") as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders' equity for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Bill Barrett Corporation and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2015 expressed an unqualified opinion on the Company's internal control over financial reporting.
/s/ Deloitte & Touche LLP
Denver, Colorado
February 26, 2015
BILL BARRETT CORPORATION
CONSOLIDATED BALANCE SHEETS
See notes to Consolidated Financial Statements.
BILL BARRETT CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
See notes to Consolidated Financial Statements.
BILL BARRETT CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
See notes to Consolidated Financial Statements.
BILL BARRETT CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
See notes to Consolidated Financial Statements.
BILL BARRETT CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)
See notes to Consolidated Financial Statements.
BILL BARRETT CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2014, 2013 and 2012
1. Organization
Bill Barrett Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the "Company") is an independent oil and gas company engaged in the exploration, development and production of oil, natural gas and NGLs. Since its inception in January 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States.
2. Summary of Significant Accounting Policies
Basis of Presentation. The accompanying Consolidated Financial Statements include the accounts of the Company. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates. In the course of preparing the Company’s financial statements in accordance with GAAP, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenues and expenses and in the disclosure of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.
Areas requiring the use of assumptions, judgments and estimates relate to the expected cash settlement of the Company’s 5% Convertible Senior Notes due 2028 ("Convertible Notes") in computing diluted earnings per share, volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization ("DD&A"), the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining asset retirement obligations, the timing of dry hole costs, impairments of proved and unproved properties, valuing deferred tax assets and estimating fair values of derivative instruments and stock-based payment awards.
Accounts Receivable. Accounts receivable is comprised of the following:
(1)
Other includes a receivable of $47.6 million (including $4.7 million due to another industry partner) related to a settlement agreement with the Department of Interior ("DOI") resulting in the cancellation of certain Cottonwood Gulch natural gas leases during the three months ended December 31, 2014.
Cash and Cash Equivalents. The Company considers all highly liquid investments with a remaining maturity of three months or less when purchased to be cash equivalents.
Oil and Gas Properties. The Company’s oil, gas and NGL exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows. If an exploratory well does find proved reserves, the costs remain capitalized and are included within additions to oil and gas properties within cash flows from investing activities in the Consolidated Statements of Cash Flows when paid. The costs of development wells are capitalized whether proved reserves are
added or not. Oil and gas lease acquisition costs are also capitalized. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.
Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.
Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage and other relevant matters.
Materials and supplies consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market value, on a first-in, first-out basis.
The following table sets forth the net capitalized costs and associated accumulated DD&A and non-cash impairments relating to the Company’s oil, natural gas and NGL producing activities:
All exploratory wells are evaluated for economic viability within one year of well completion. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. As of December 31, 2014 and 2013, there were no exploratory well costs that had been capitalized for a period greater than one year since the completion of drilling.
The Company reviews proved oil and gas properties on a field-by-field basis for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying value of a property exceeds the undiscounted future cash flows, the Company will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors. The Company has no guarantee that the undiscounted future cash flows analysis of its proved property represents the applicable market value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.
The Company recognized non-cash impairment charges, which were included within impairment, dry hole costs and abandonment expense in the Consolidated Statements of Operations, as follows:
(1)
As a result of the Powder River Oil Divestiture (see Note 4), the carrying values of the remaining properties were analyzed relative to their estimated fair market value. As a result, the Company recognized impairment of $14.8 million. These properties were classified as held for sale as of December 31, 2014. The remaining impairment of $1.0 million related to the West Tavaputs Divestiture (see Note 4) based upon a true up of previously estimated carrying value.
(2)
As a result of unfavorable drilling and completion results in the Paradox Basin, the Company recognized an impairment of $11.6 million related to unproved oil and gas properties. In addition, the Company recognized an impairment of $6.1 million related to certain unproved oil and gas properties in the Uinta Basin as a result of no future plans to evaluate certain acreage positions. The Company recognized an impairment of $6.4 million to unproved oil and gas properties as the result of the Powder River Oil Divestiture discussed in (1) above.
(3)
As a result of an analysis of remaining carrying values relative to fair market values resulting from the West Tavaputs Divestiture (see Note 4), $207.0 million and $2.5 million of proved and unproved property impairment, respectively, was incurred during the year ended December 31, 2013. As a result of no future plans to evaluate remaining acreage and estimated market value below carrying value within various exploration projects, an additional $17.1 million of unproved property impairment was incurred during the year ended December 31, 2013.
(4)
As a result of unfavorable natural gas exploratory results, no future plans to evaluate remaining acreage and estimated market value below our carrying value within exploration projects, $37.3 million of unproved property impairment was incurred during the year ended December 31, 2012.
The provision for DD&A of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas and NGLs are converted to an oil equivalent, Boe, at the standard rate of six Mcf to one Boe and forty-two gallons to one Boe, respectively. Estimated future dismantlement, restoration and abandonment costs are taken into consideration by this calculation.
Accounts Payable and Accrued Liabilities. Accounts payable and accrued liabilities are comprised of the following:
Environmental Liabilities. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Environmental liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated.
Revenue Recognition. Oil, gas and NGL revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. The Company uses the sales method to account for gas and NGL imbalances. Under this method, revenues are recorded on the basis of gas and NGLs actually sold by the Company. In addition, the Company records revenues for its share of gas and NGLs sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenues for other owners' gas and NGLs sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company's remaining over- and under- produced gas and NGLs balancing positions are taken into account in determining the Company's proved oil, gas and NGL reserves. Imbalances at December 31, 2014 and 2013 were not material.
Derivative Instruments and Hedging Activities. The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its oil, natural gas and NGL sales by reducing its exposure to price fluctuations. Derivative instruments are recorded at fair market value and are included in the Consolidated Balance Sheets as assets or liabilities.
Income Taxes. Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes also include tax credits and net operating losses that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates.
The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold are recognized.
Earnings/Loss Per Share. Basic net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income per common share calculations consist of nonvested equity shares of common stock, in-the-money outstanding stock options to purchase the Company’s common stock and shares into which the Convertible Notes are convertible. No potential common shares are included in the computation of any diluted per share amount when a net loss exists, as was the case for the year ended December 31, 2013.
In satisfaction of its obligation upon conversion of the Convertible Notes, the Company may elect to deliver, at its option, cash, shares of its common stock or a combination of cash and shares of its common stock. As of December 31, 2014, the Company expected to settle the remaining Convertible Notes in cash. Therefore, the treasury stock method was used to measure the potentially dilutive impact of shares associated with that remaining conversion feature. The Company has the right at any time with at least 30 days’ notice to call the Convertible Notes and the holders have the right to require the Company to purchase the notes on March 20, 2015, March 20, 2018 and March 20, 2023. The Convertible Notes have not been dilutive since their issuance in March 2008 and, therefore, did not impact the diluted net income per common share calculation for the years ended December 31, 2014 and 2012. The diluted net income per common share excludes the anti-dilutive effect of 1,406,938 and 3,162,436 stock options and nonvested equity shares of common stock for the years ended December 31, 2014 and 2012, respectively.
The following table sets forth the calculation of basic and diluted net income (loss) per share:
Industry Segment and Geographic Information. The Company operates in one industry segment, which is the development and production of crude oil, natural gas and NGLs, and all of the Company’s operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment.
New Accounting Pronouncements. In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The objective of this update is to provide guidance in GAAP about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The standard will be adopted prospectively.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the potential impact that the adoption will have on the Company’s disclosures and financial statements.
Reclassifications. Certain amounts in the prior period Consolidated Balance Sheets have been reclassified to conform to the current period's presentation. During the year ended December 31, 2014, we changed the presentation of unproved oil and gas properties to present unproved oil and gas properties, net of impairment. Impairment of unproved oil and gas properties was included in accumulated depreciation, depletion, amortization and impairment in the prior period. The total property and equipment subtotal was not affected by this reclassification nor were any other financial statements.
3. Supplemental Disclosures of Cash Flow Information
Supplemental cash flow information is as follows:
(1)
Includes a receivable of $42.9 million related to a settlement agreement with the Department of Interior ("DOI") resulting in the cancellation of certain Cottonwood Gulch natural gas leases in 2014.
4. Divestitures and Assets Held for Sale
Divestitures. During the year ended December 31, 2014, the Company completed the sale or exchange of the majority of its Powder River Basin assets (the "Powder River Oil Divestiture") in four separate transactions with effective dates of April 1, 2014 and closing dates during the three months ended September 30, 2014. The sale resulted in net cash proceeds of $30.0 million, after initial closing adjustments. Three transactions involved the cumulative sale of 17,497 net mineral acres. The fourth transaction involved an exchange of 29,015 net mineral acres in the Powder River Basin for 7,856 net mineral acres within the southern block of the Company’s operated Northeast Wattenberg area of the Denver-Julesburg Basin, valued at $71.0 million. Assets sold or exchanged as part of the overall Powder River Oil Divestiture included $86.2 million in proved and $40.6 million in unproved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment of $33.1 million and $1.3 million in asset retirement obligations. A loss on sale of $24.5 million related to these transactions is included within operating expenses in the Consolidated Statements of Operations. The divestiture proceeds are subject to various purchase price adjustments incurred in the normal course of business and will be finalized in 2015.
On September 30, 2014, the Company completed the sale of its Gibson Gulch natural gas program in the Piceance Basin (the "Piceance Divestiture") with an effective date of July 1, 2014. The Company received $498.7 million in cash proceeds, after initial closing estimates. In addition to the cash proceeds, the Company recognized non-cash proceeds of $22.4 million related to the relief of the Company's asset retirement obligation and $36.1 million related to the transfer of the Company's lease financing obligation described in Note 5 (the "Lease Financing Obligation"). A loss on sale of $79.5 million related to this transaction is included within operating expenses in the Consolidated Statements of Operations. The divestiture proceeds are subject to various purchase price adjustments incurred in the normal course of business and will be finalized in 2015. The carrying amounts by major asset class within the disposal group for the Piceance Divestiture are summarized below (in thousands):
On December 10, 2013, the Company completed the sale of its West Tavaputs natural gas assets in the Uinta Basin (the "West Tavaputs Divestiture"). The Company received $308.7 million in cash proceeds, after closing adjustments. The divestiture proceeds were subject to various purchase price adjustments incurred in the normal course of business and were finalized during 2014. The Company recognized an impairment loss of $1.0 million during the year ended December 31, 2014 related to these assets based upon a true up of previously estimated carrying value. An initial impairment loss of $209.5 million related to these assets was recognized during the year ended December 31, 2013.
On December 31, 2012, the Company completed the sale of natural gas assets including 100% of its Wind River Basin, 100% of the Powder River Basin coalbed methane assets, and a non-operating working interest in its Gibson Gulch-Piceance Basin development property (the "2012 Divestiture"). The Company received $325.3 million in cash proceeds and recognized a $4.5 million pre-tax loss included in other operating revenues for the year ended December 31, 2012. Due to final post-closing adjustments, the Company recognized an additional $3.1 million pre-tax loss included in other operating revenues for the year ended December 31, 2013.
Assets Held for Sale. The Company began marketing its remaining Powder River Basin assets, including 19,492 net mineral acres, during 2014. Therefore, the related assets and liabilities were classified as held for sale in the Consolidated Balance Sheet as of December 31, 2014. Upon the classification as held for sale, the assets were analyzed relative to their fair
market values. The Company recognized proved and unproved property impairment of $14.8 million and $6.4 million, respectively, during the year ended December 31, 2014.
5. Long-Term Debt
The Company’s outstanding debt is summarized below:
(1)
The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure.
(2)
The aggregate estimated fair value of the Convertible Notes was approximately $25.1 million as of December 31, 2014 and 2013, based on reported market trades of these instruments.
(3)
The Company has the right at any time, with at least 30 days’ notice, to call the Convertible Notes, and the holders have the right to require the Company to purchase the notes on each of March 20, 2015, March 20, 2018 and March 20, 2023.
(4)
The aggregate estimated fair value of the 7.625% Senior Notes was approximately $359.8 million and $430.2 million as of December 31, 2014 and 2013, respectively, based on reported market trades of these instruments.
(5)
The aggregate estimated fair value of the 7.0% Senior Notes was approximately $366.0 million and $417.0 million as of December 31, 2014 and 2013, respectively, based on reported market trades of these instruments.
(6)
The aggregate estimated fair value of the Lease Financing Obligation was approximately $3.5 million and $41.7 million as of December 31, 2014 and 2013, respectively. The decrease in estimated fair value is primarily related to the sale of equipment in the Piceance Divestiture. As there is no active public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.
(7)
The current portion of long-term debt as of December 31, 2014 includes the current portion of the Lease Financing Obligation and the principal amount of the Convertible Notes. The Company classified the Convertible Notes as a current obligation as of December 31, 2014 as the holders may require us to purchase their Convertible Notes for cash on March 20, 2015.
(8)
The current portion of long-term debt as of December 31, 2013 includes the current portion of the Lease Financing Obligation.
Amended Credit Facility
The Company’s Amended Credit Facility has a maturity date of October 31, 2016 and current commitments and borrowing base of $375.0 million. As of December 31, 2014, the Company had no amounts outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit has been issued under the Amended Credit Facility, which reduced the current available borrowing capacity of the Amended Credit Facility as of December 31, 2014 to $349.0 million.
Interest rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the commitment fee is between 0.375% to 0.5% based on borrowing base utilization. The average annual interest rates incurred on the Amended Credit Facility were 1.9% and 2.0% for the years ended December 31, 2014 and 2013, respectively.
The borrowing base is required to be re-determined twice per year. On September 30, 2014, the borrowing base was reduced to $375.0 million based on June 30, 2014 reserves as adjusted for the Piceance and Powder River Oil Divestitures and the Company's hedge position. Future semi-annual borrowing bases will be computed based on proved oil, natural gas and
NGL reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt of the Company.
The Amended Credit Facility also contains certain financial covenants. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance.
5% Convertible Senior Notes Due 2028
On March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012, $147.2 million of the outstanding principal amount, or approximately 85% of the outstanding Convertible Notes, were put to the Company and redeemed by the Company at par. The Company settled the notes in cash. After the redemption, $25.3 million aggregate principal amount of the Convertible Notes was outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by the Company. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of the Company’s existing and future senior unsecured indebtedness, are senior in right of payment to all of the Company’s future subordinated indebtedness, and are effectively subordinated to all of the Company’s secured indebtedness with respect to the collateral securing such indebtedness. The Convertible Notes are structurally subordinated to all present and future secured and unsecured debt and other obligations of the Company’s subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the 7.625% Senior Notes and the 7.0% Senior Notes.
The Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year. Holders of the remaining Convertible Notes may require the Company to purchase all or a portion of their Convertible Notes for cash on each of March 20, 2015, March 20, 2018 and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. The Company has the right, with at least 30 days’ notice, to call the Convertible Notes. The Company classified the Convertible Notes as a current obligation on the Consolidated Balance Sheets as of December 31, 2014 as the holders may require us to purchase their Convertible Notes for cash on March 20, 2015.
7.625% Senior Notes Due 2019
On September 27, 2011, the Company issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. The 7.625% Senior Notes mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 beginning April 1, 2012. The 7.625% Senior Notes are senior unsecured obligations of the Company and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness, including the Company’s Convertible Notes and 7.0% Senior Notes. The 7.625% Senior Notes are redeemable at the Company’s option at a redemption price of 103.813% of the principal amount of the notes on October 1, 2015. The 7.625% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.0% Senior Notes. The 7.625% Senior Notes include certain covenants that limit the Company’s ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that prohibit the Company from paying dividends. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance.
7.0% Senior Notes Due 2022
On March 12, 2012, the Company issued $400.0 million in aggregate principal amount of 7.0% Senior Notes due 2022 at par. The 7.0% Senior Notes mature on October 15, 2022. Interest is payable in arrears semi-annually on April 15 and October 15 of each year. The 7.0% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness, including the Company’s Convertible Notes and 7.625% Senior Notes. The 7.0% Senior Notes are redeemable at the Company's option on October 15, 2017 at a redemption price of 103.5% of the principal amount of the notes. The 7.0% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.625% Senior Notes. The 7.0% Senior Notes include certain covenants that limit the Company’s ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that prohibit the Company from paying dividends. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance.
Lease Financing Obligation Due 2020
On July 23, 2012, the Company entered into the Lease Financing Obligation, whereby the Company received $100.8 million through the sale and subsequent leaseback of existing compressors and related facilities owned by the Company. The
Lease Financing Obligation expires on August 10, 2020, and the Company has the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligation also contains an early buyout option where the Company may purchase the equipment on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.3%. See Note 13 for discussion of aggregate minimum future lease payments. As the result of the disposition of equipment in the West Tavaputs Divestiture and the Piceance Divestiture, the Company's remaining Lease Financing Obligation has been reduced to $3.6 million as of December 31, 2014 and the early buyout option is reduced to $1.8 million.
The following table summarizes, for the periods indicated, the cash or accrued portion of interest expense related to the Amended Credit Facility, 9.875% Senior Notes that were redeemed in full on July 15, 2013, Convertible Notes, 7.625% Senior Notes, 7.0% Senior Notes and the Lease Financing Obligation along with the non-cash portion resulting from the amortization of the debt discount and transaction costs through interest expense:
(1)
Cash interest includes amounts related to interest and commitment fees paid on the Amended Credit Facility and participation and fronting fees paid on the letter of credit.
(2)
The stated interest rate for the 9.875% Senior Notes was 9.875% per annum with an effective interest rate of 11.2% per annum. The Company redeemed the 9.875% Senior Notes in full on July 15, 2013.
(3)
The stated interest rate for the Convertible Notes is 5% per annum. The effective interest rate of the Convertible Notes includes amortization of the debt discount, which represented the fair value of the equity conversion feature at the time of issue. The stated interest rate of 5% on the Convertible Notes is the effective interest rate of the $25.3 million remaining principal balance, as the related debt discount was fully amortized as of March 31, 2012.
(4)
The stated interest rate for the 7.625% Senior Notes is 7.625% per annum with an effective interest rate of 8.0% per annum.
(5)
The stated interest rate for the 7.0% Senior Notes is 7.0% per annum with an effective interest rate of 7.2% per annum.
(6)
The effective interest rate for the Lease Financing Obligation is 3.3% per annum. The decrease in cash interest from $2.9 million to $0.6 million for the years ended December 31, 2013 and 2014, respectively, is due to the West Tavaputs and Piceance Divestitures.
6. Asset Retirement Obligations
A reconciliation of the Company’s asset retirement obligations for the year ended December 31, 2014, 2013 and 2012 is as follows:
7. Fair Value Measurements
Assets and Liabilities Measured on a Recurring Basis
The Company’s financial instruments, including cash and cash equivalents, accounts and notes receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Amended Credit Facility, as discussed in Note 5, approximates its fair value due to its floating rate structure based on the LIBOR spread and the Company's borrowing base utilization.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) for valuation as a practical expedient for assigning fair value. The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market and income approaches for recurring fair value measurements and utilizes the best available information. Given the Company’s historical market transactions, its markets and instruments are fairly liquid. Therefore, the Company has been able to classify fair value balances based on the observability of those inputs. A fair value hierarchy was established that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed securities and U.S. government treasury securities.
Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.
Level 3 - Pricing inputs include significant inputs that are generally less observable than objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At each balance
sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.
The following tables set forth by level within the fair value hierarchy the Company’s financial assets and financial liabilities that were measured at fair value on a recurring basis. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of assets and liabilities and their placement within the fair value hierarchy levels.
All fair values reflected in the table above and on the Consolidated Balance Sheets have been adjusted for non-performance risk. For applicable financial assets carried at fair value, the credit standing of the counterparties is analyzed and factored into the fair value measurement of those assets. In addition, the fair value measurement of a liability has been adjusted to reflect the nonperformance risk of the Company. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.
Level 1 Fair Value Measurements - The Company maintains a non-qualified deferred compensation plan (as discussed in more detail in Note 11) which allows certain management employees to defer receipt of a portion of their compensation. The Company maintains assets for the deferred compensation plan in a rabbi trust. The assets of the rabbi trust are invested in publicly traded mutual funds and are recorded in prepayments and other current assets and deferred financing costs and other noncurrent assets on the Consolidated Balance Sheets. The Company also has highly liquid short term investments in money market funds. The deferred compensation plan financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs. The money market fund investments are recorded at carrying value, which approximates fair value, and represents Level 1 inputs. The fair values of the Company’s fixed rate $400.0 million principal 7.625% Senior Notes and $400.0 million principal 7.0% Senior Notes totaled $725.8 million and $847.2 million as of December 31, 2014 and 2013, respectively. The fair values of the Company's fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.
Level 2 Fair Value Measurements - The fair value of oil, natural gas and NGL swaps and forwards are estimated using a combined income and market valuation methodology with a mid-market pricing convention based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. The Company did not make any adjustments to the obtained curves. The pricing services publish observable market information from multiple brokers and exchanges. No proprietary models are used by the pricing services for the inputs. The Company utilized the counterparties’ valuations to assess the reasonableness of the Company’s valuations.
There is no active, public market for the Company’s Amended Credit Facility, Convertible Notes or Lease Financing Obligation. The Amended Credit Facility balance of zero and $115.0 million as of December 31, 2014 and 2013, respectively, approximates its fair value due to its floating rate structure. The Convertible Notes fair value of $25.1 million as of December 31, 2014 and 2013 is measured based on market-based parameters of the various components of the Convertible Notes and over the counter trades. The Lease Financing Obligation fair values of $3.5 million and $41.7 million as of December 31, 2014 and 2013, respectively, are measured based on market-based parameters of comparable term secured financing instruments. The fair value measurements for the Amended Credit Facility, Convertible Notes and Lease Financing Obligation represent Level 2 inputs.
Level 3 Fair Value Measurements - As of December 31, 2014 and 2013, the Company did not have assets or liabilities that were measured on a recurring basis classified under a Level 3 fair value hierarchy.
Assets and Liabilities Measured on a Non-recurring Basis
The Company utilizes fair value on a non-recurring basis to perform impairment tests on its property and equipment when required. During the year ended December 31, 2014, the Company recognized impairment on proved and unproved property of $39.8 million. Included in the total impairment charge of $39.8 million was $21.1 million of impairment charges related to the remaining Powder River Basin assets for which the Company utilized third party purchase offers as the basis for determining fair value. This property was classified as held for sale as of December 31, 2014. The inputs used to determine such fair value for other non-recurring impairment tests are primarily based upon internally developed cash flow models as well as available external market data and would generally be classified within Level 3.
(1)
See Note 2 for additional details on impairment expense recognized.
(2)
Includes $6.7 million of net proved property and $2.5 million of net unproved property associated with properties held for sale as of December 31, 2014.
The Company utilizes fair value on a non-recurring basis to perform impairment tests on its property and equipment when required. During the year ended December 31, 2013, the Company recorded impairment charges of $226.6 million on proved and unproved oil and gas properties. Included in the total impairment charge of $226.6 million was $209.5 million of impairment charges related to the West Tavaputs area of the Uinta Basin for which the Company utilized third party purchase offers as the basis for determining fair value. This property was sold in December 2013. The inputs used to determine such fair value for other non-recurring impairment tests are primarily based upon internally developed cash flow models as well as available external market data and would generally be classified within Level 3.
(1)
See Note 2 for additional details on impairment expense recognized.
8. Derivative Instruments
The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable cash flow from its production revenues by reducing its exposure to commodity price fluctuations. The Company has entered into financial commodity swap contracts related to the sale of a portion of the Company’s production. The Company does not enter into derivative instruments for speculative or trading purposes.
In addition to financial contracts, the Company at times may be party to various physical commodity contracts for the sale of oil, natural gas and NGLs that have varying terms and pricing provisions. These physical commodity contracts qualify for
the normal purchase and normal sale exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil, natural gas and NGL production revenues at the time of settlement.
All derivative instruments, other than those that meet the normal purchase and normal sale exception, as mentioned above, are recorded at fair value and included on the Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location, as well as the gross and net fair value amounts of all derivative instruments presented on the Consolidated Balance Sheets as of the dates indicated.
(1)
Amounts are netted against derivative asset balances with the same counterparty, and therefore, are presented as a net asset on the Consolidated Balance Sheets.
(2)
Amounts are netted against derivative liability balances with the same counterparty, and therefore are presented as a net liability on the Consolidated Balance Sheets.
(3)
As of December 31, 2014 and 2013, this line item on the Consolidated Balance Sheets includes $3.0 million and $3.5 million of other noncurrent liabilities, respectively.
Effective January 1, 2012, the Company elected to discontinue hedge accounting prospectively. As a result, the mark-to-market value of all commodity hedge instruments within AOCI at December 31, 2011 was frozen in AOCI as of the de-designation date and was reclassified into earnings in future periods as the original hedged transactions occurred. All cash flow hedged transactions were completed by December 31, 2014. The following table summarizes the cash flow hedge gains, net of tax, and their locations on the Consolidated Balance Sheets and Consolidated Statements of Operations for the periods indicated:
(1)
Presented net of income tax expense of $0.4 million, $2.8 million and $30.5 million for the years ended December 31, 2014, 2013 and 2012, respectively.
(2)
Gains reclassified from AOCI into income are included in the oil, gas and NGL production revenues in the Consolidated Statements of Operations.
As of December 31, 2014, the Company had financial instruments in place to hedge the following volumes for the periods indicated:
The table below summarizes the commodity derivative gains and losses the Company recognized related to its oil, gas and NGL derivative instruments for the periods indicated:
(1)
Included in oil, gas and NGL production revenues in the Consolidated Statements of Operations.
(2)
Included in commodity derivative gain (loss) in the Consolidated Statements of Operations.
The Company’s derivative financial instruments are generally executed with major financial or commodities trading institutions that expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company had hedges in place with eight different counterparties as of December 31, 2014. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. The creditworthiness of counterparties is subject to continual review by management, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties.
It is the Company’s policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility or potential lenders in the Amended Credit Facility. The Company’s derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. ("ISDA") Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Amended Credit Facility. The Company has set-off provisions in its derivative contracts with lenders under its Amended Credit Facility which, in the event of a counterparty default, allow the Company to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed the Company under derivative contracts. Where the counterparty is not a lender under the Company’s Amended Credit Facility, it may not be
able to set-off amounts owed by the Company under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility. The Company does not have any derivative balances that are offset by cash collateral.
9. Income Taxes
The expense for income taxes consisted of the following for the periods indicated:
Income tax expense differed from the amounts computed by applying the U.S. federal income tax rate of 35% to pretax income from continuing operations as a result of the following:
The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at December 31, 2014 and 2013 are presented below:
At December 31, 2014, the Company had approximately $168.2 million of federal tax net operating loss carryforwards which expire beginning in 2027. The Company has a federal alternative minimum tax credit carryforward of $1.7 million, which has no expiration date.
In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense. At December 31, 2014, the Company had approximately $7.9 million of state income tax credit carryforwards that begin expiring in 2018. A valuation allowance against these credits was recorded in 2011. It is currently estimated that the state income tax credits will not be utilized because the Company does not project to have sufficient future taxable income in the appropriate jurisdictions, and therefore the valuation allowance on the full amount of the credit carryforwards will remain.
At December 31, 2014 and 2013, the Consolidated Balance Sheet reflected a net deferred tax liability of $177.8 million and $161.5 million, respectively.
The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits. The Company did not have any additions, reductions or settlements of unrecognized tax benefits in the years ended December 2014, 2013 and 2012. In 2014, the Company generated no uncertain tax positions.
The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. As of December 31, 2014, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the current year.
The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and in various states. With few exceptions, the Company is subject to U.S. federal tax examination for years 2011 through 2014 and is subject to state tax examination for years 2010 through 2014.
10. Stockholders' Equity
Common and Preferred Stock. The Company’s authorized capital structure consists of 75,000,000 shares of preferred stock, par value $0.001 per share and 150,000,000 shares of common stock, par value $0.001 per share. In October 2004, 150,000 shares of $0.001 per share par value preferred stock were designated as Series A Junior Participating Preferred Stock, none of which are outstanding. The remainder of the authorized preferred stock is undesignated. There are no issued and outstanding shares of preferred stock.
When issued, each share of Series A Junior Participating Preferred Stock will entitle the holder thereof to 1,000 votes on all matters submitted to a vote of the Company’s stockholders.
Treasury Stock. The Company may occasionally acquire treasury stock, which is recorded at cost, in connection with the vesting and exercise of stock-based awards or for other reasons. As of December 31, 2014, all treasury stock held by the Company was retired.
The following table reflects the activity in the Company’s common and treasury stock for the periods indicated:
Accumulated Other Comprehensive Income. The components of accumulated other comprehensive income and related tax effects for the years ended December 31, 2012, 2013 and 2014 were as follows:
11. Equity Incentive Compensation Plans and Other Employee Benefits
The Company maintains various stock-based compensation plans and other employee benefit plans as discussed below. Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period).
The following table presents the non-cash stock-based compensation related to equity awards for the periods indicated:
(1)
Includes non-cash stock-based compensation related to director fees of $0.1 million, $0.4 million and $0.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Unrecognized compensation cost as of December 31, 2014 was $15.7 million related to grants of nonvested stock options and nonvested equity shares of common stock that are expected to be recognized over a weighted-average period of 2.3 years.
Stock Options and Nonvested Equity Shares. In May 2012, the Company’s stockholders approved and the Company adopted its 2012 Equity Incentive Plan (the "2012 Incentive Plan"). The purpose of the 2012 Incentive Plan is to enhance the Company’s ability to attract and retain officers, employees and directors and to provide such persons with an interest in the Company aligned with the interests of stockholders. The 2012 Incentive Plan provides for the grant of stock options (including incentive stock options and non-qualified stock options) and other awards, including performance units, performance shares, share awards, share units, restricted stock, cash incentive, and stock appreciation rights or SARs.
The aggregate number of shares that the Company may issue under the 2012 Incentive Plan may not exceed 2,051,402 shares, subject to adjustment for future stock splits, stock dividends and similar changes in the Company’s capitalization. Shares underlying grants that expire without being exercised or are forfeited are available for grant under the 2012 Incentive Plan. The aggregate number of shares of common stock subject to options, stock appreciation rights, or performance-based awards granted to a participant during any calendar year may not exceed 500,000 shares. The 2012 Incentive Plan provides that all awards granted under the 2012 Incentive Plan expire not more than 10 years from the grant date and have an exercise price of no less than the closing price of the Company’s common stock on the date of grant.
Currently, the Company’s practice is to issue new shares upon stock option exercise. The Company does not expect to repurchase any shares in the open market or issue treasury shares to settle any such exercises. For the years ended December 31, 2014, 2013 and 2012, the Company did not pay cash to repurchase any stock option exercises.
The fair value of each share-based option award under all of the Company’s plans is estimated on the date of grant using a Black-Scholes pricing model that incorporates the assumptions noted in the following table. Estimated expected volatilities were based upon historical volatility of the Company’s common stock. The Company does not expect to declare or pay dividends in the foreseeable future; thus, the Company used a 0% expected dividend yield, which is comparable to most of its peers in the industry. The expected terms range from 0.09 years to 6.0 years, or a weighted average of 4.3 years to 4.6 years, based on 25% of each grant’s vesting on each anniversary date and factoring in potential blackout dates, historic exercises and expectations of future employee behavior. The risk-free rate is based on the U.S. Treasury yield curve in effect on the date of grant and extrapolated to approximate the expected life of the award. The Company estimated a 4% to 10% annual compounded forfeiture rate for the year 2012 based on historical employee turnover and actual forfeitures. The Company did not grant any share-based option awards during the years 2014 or 2013.
A summary of share-based option activity under all the Company's plans as of December 31, 2014, and changes during the year then ended, is presented below:
The per share weighted-average grant date fair value of options granted for the year ended December 31, 2012 was $11.02. The total intrinsic value of options exercised for the years ended December 31, 2014, 2013 and 2012 were $0.1 million, $0.5 million and $0.4 million, respectively. With respect to stock option exercises, the Company received $0.1 million, $6.4 million, and $0.7 million for the years ended December 31, 2014, 2013 and 2012, respectively.
A summary of the Company’s nonvested equity shares of common stock as of December 31, 2014, 2013 and 2012, and changes during the years then ended, is presented below:
Equity common stock units were issued beginning on July 1, 2012 and will be converted to shares of common stock as they vest. As of December 31, 2014, equity common stock units have only been issued for payment of director fees. A summary of the Company’s nonvested equity share units of common stock as of December 31, 2014, 2013 and 2012, and changes during the years then ended, is presented in the table below:
The fair value of equity awards vested for the years ended December 31, 2014, 2013 and 2012 was $8.0 million, $8.1 million and $8.6 million, respectively.
Performance Share Programs
2014 Program. In February 2014, the Compensation Committee of the Board of Directors of the Company approved a new performance share program (the "2014 Program") pursuant to the 2012 Equity Incentive Plan. The performance-based awards contingently vest in May 2017, depending on the level at which the performance goals are achieved. The performance goals, which will be measured over the three year period ending December 31, 2016, consist of the Company's total shareholder return ("TSR") ranking relative to a defined peer group's individual TSRs ("Relative TSR") (weighted at 60%) and the percentage change in discretionary cash flow per debt adjusted share relative to a defined peer group's percentage calculation ("DCF per Debt Adjusted Share") (weighted at 40%). The Relative TSR and DCF per Debt Adjusted Share goals will vest at 25% of the total award for performance met at the threshold level, 100% at the target level and 200% at the stretch level. If the actual results for a metric are between the threshold and target levels or between the target and stretch levels, the vested number of shares will be prorated based on the actual results compared to the threshold, target and stretch goals. If the threshold metrics are not met, no shares will vest. In any event, the total number of shares of common stock that could vest will not exceed 200% of the original number of performance shares granted. At the end of the three year vesting period, any shares that have not vested will be forfeited. A total of 315,661 shares were granted under this program during the year ended December 31, 2014. All compensation expense related to the TSR metric will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. All compensation expense related to the DCF per Debt Adjusted Share metric will be based upon the number of shares expected to vest at the end of the three year period.
2013 Program. In February 2013, the Compensation Committee approved a new performance share program (the "2013 Program") pursuant to the 2012 Equity Incentive Plan. The performance-based awards contingently vest in May 2016, depending on the level at which the performance goals are achieved. The performance goals, which will be measured over the three year period ending December 31, 2015, consist of the Company's Relative TSR (weighted at 33 1/3%), the percentage change in discretionary cash flow per debt adjusted share relative to a defined peer group's percentage calculation ("DCF per Debt Adjusted Share") (weighted at 33 1/3%) and percentage change in proved oil, natural gas and NGL reserves per debt adjusted share ("Reserves per Debt Adjusted Share") (weighted at 33 1/3%). The Relative TSR and DCF per Debt Adjusted Share goals will vest at 25% of the total award for performance met at the threshold level, 100% at the target level and 200% at the stretch level. The Reserves per Debt Adjusted Share goal will vest at 50% of the total award for performance met at the threshold level, 100% at the target level and 200% at the stretch level. If the actual results for a metric are between the threshold and target levels or between the target and stretch levels, the vested number of shares will be prorated based on the actual results compared to the threshold, target and stretch goals. If the threshold metrics are not met, no shares will vest. In any event, the total number of shares of common stock that could vest will not exceed 200% of the original number of performance shares granted. At the end of the three year vesting period, any shares that have not vested will be forfeited. A total of 450,544 shares were granted under this program during the year ended December 31, 2013. All compensation expense related to the Relative TSR metric will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.
All compensation expense related to the DCF per Debt Adjusted Share metric and the Reserves per Debt Adjusted Share metric will be based upon the number of shares expected to vest at the end of the three year period.
2012 Program. In March 2012, the Compensation Committee approved a new performance share program (the "2012 Program"). The performance-based awards contingently vest in May 2015, depending on the level at which the performance goals are achieved. The performance goals, which will be measured over the three year period ending December 31, 2014, consist of the Company's TSR ranking relative to a defined peer group's individual TSR (weighted at 33 1/3%), the percentage change in DCF per Debt Adjusted Share relative to a defined peer group's percentage calculation (weighted at 33 1/3%) and the change in proved oil and natural gas reserves per debt adjusted share (weighted at 33 1/3%). Fifty percent of the total award will vest for performance met at the threshold level, 100% will vest at the target level and 200% will vest at the stretch level. If the actual results for a metric are between the threshold and target levels or between the target and stretch levels, the vested number of shares will be adjusted on a prorated basis of the actual results compared to the threshold, target and stretch goals. If the threshold metrics are not met, no shares will vest. In any event, the total number of shares of common stock that could vest will not exceed 200% of the original number of performance shares granted. At the end of the three year vesting period, any shares that have not vested will be forfeited. All compensation expense related to the TSR metric will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. All compensation expense related to the DCF per Debt Adjusted Share and oil and natural gas reserves per debt adjusted share metrics will be based upon the number of shares expected to vest at the end of the three year period. A total of 179,987 shares were granted under this program during the year ended December 31, 2012. Based upon the Company's performance through 2014, none of the 2012 Program performance shares will vest in May 2015.
2010 Program. In February 2010, the Compensation Committee approved a performance share program (the "2010 Program"). Upon commencement of the 2010 Program and during each subsequent year of the 2010 Program through 2013, the Compensation Committee met to approve target and stretch goals for certain operational or financial metrics that are selected by the Compensation Committee for the upcoming year and to determine whether metrics for the prior year have been met. As new goals are established each year for the performance-based awards, a new grant date and a new fair value are created for financial reporting purposes for those shares that could potentially vest in the upcoming year. Compensation expense is recognized based upon an estimate of the extent to which the performance goals would be met. If such goals are not met, no compensation expense is recognized and any previously recognized compensation expense is reversed.
The 2010 Program has both performance-based and market-based goals. All compensation expense related to the market-based goals will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. Based on Company performance in 2010, 2011, 2012 and 2013, 25.9%, 26.6%, 0.0% and 19.8%, respectively, of the 2010 Program performance-based shares vested in February 2011, February 2012, February 2013 and February 2014, respectively, for a total of 72.3% of the total performance-based shares vested over the four year vesting period. A total of 59,582, 57,944, zero and 21,968 shares vested in February 2011, February 2012, February 2013 and February 2014, respectively.
Based on the 2010 Program market-based goals, which were based on the Company's TSR ranking relative to a defined peer group's individual TSR, 37.5%, 12.5%, 0.0% and 33.4% vested in February 2011, 2012, 2013 and 2014, respectively, based on the Company's rankings as of December 31, 2010, 2011, 2012, and 2013, respectively, for a total of 83.4% of the total market-based shares vested over the four year vesting period. A total of 21,574, 6,801, zero and 9,242 shares vested in February 2011, February 2012, February 2013 and February 2014, respectively.
A summary of the Company's non-vested performance-based equity shares of common stock as of December 31, 2014, 2013 and 2012, and changes during the years then ended, is presented below:
(1)
As the Compensation Committee approved new performance metrics for the vesting of performance shares in the upcoming year, a new grant date was then created for any unvested awards that were granted in previous years, and a new fair value was established for financial reporting purposes.
The fair value of the performance-based shares vested in the years ended December 31, 2014 and 2012 was $0.8 million and $2.6 million, respectively.
Director Fees. The Company's non-employee, or outside, directors, may elect to receive all or a portion of their annual retainer and meeting fees in the form of restricted stock units ("RSUs"), which are settled with shares of the Company's common stock, issued pursuant to the Company's 2012 Incentive Plan. After each quarter, RSUs with a value equal to the fees payable for that quarter, calculated using the closing price for the Company's common stock on the last trading day of the quarter, will be delivered to each outside director who elected before that quarter to receive RSUs for payment of director fees. These nonvested RSUs will vest immediately at the end of the applicable quarter. Once vested, the RSUs will settle at the end of the applicable quarter or such later date elected by the director.
A summary of the Company's directors' fees and equity-based compensation for the years ended December 31, 2014, 2013 and 2012 is presented below:
Other Employee Benefits-401(k) Savings Plan. The Company has an employee-directed 401(k) savings plan (the "401(k) Plan") for all eligible employees over the age of 21. Under the 401(k) Plan, employees may make voluntary contributions based upon a percentage of their pretax income, subject to statutory limitations.
The Company matches 100% of each employee's contribution, up to 6% of the employee's pretax income, with 50% of the match made with the Company's common stock. The Company's cash and common stock contributions are fully vested upon the date of match, and employees can immediately sell the portion of the match made with the Company's common stock. The Company made matching cash and common stock contributions of $1.7 million, $1.9 million and $2.0 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Deferred Compensation Plan. In 2010, the Company adopted a non-qualified deferred compensation plan for certain employees and officers whose eligibility to participate in the plan was determined by the Compensation Committee of the Company's Board of Directors. The Company makes matching cash contributions on behalf of eligible employees up to 6% of the employee's cash compensation once the contribution limits are reached on the Company's 401(k) Plan. All amounts deferred and matched under the plan vest immediately. Deferred compensation, including accumulated earnings on the participant-directed investment selections, is distributable in cash at participant-specified dates or upon retirement, death, disability, change in control or termination of employment.
The table below summarizes the activity in the plan during the years ended December 31, 2014 and 2013, and the Company’s ending deferred compensation liability as of December 31, 2014 and 2013:
The Company has established a rabbi trust to offset the deferred compensation liability and protect the interests of the plan participants. The investments in the rabbi trust seek to offset the change in the value of the related liability. As a result, there is no expected impact on earnings or earnings per share from the changes in market value of the investment assets because the changes in market value of the trust assets are offset by changes in the value of the deferred compensation plan liability. The gains and losses from changes in fair value of the investments are included in interest and other income in the Consolidated Statements of Operations.
The following table represents the Company's activity in the investment assets held in the rabbi trust during the years ended December 31, 2014 and 2013:
12. Significant Customers and Other Concentrations
Significant Customers. During 2014, two customers individually accounted for over 10% of the Company's oil, gas and NGL production revenues. During 2013, one customer individually accounted for over 10% of the Company’s oil, gas and NGL production revenues. During 2012, two customers individually accounted for over 10% of the Company’s oil, gas and NGL production revenues. Although diversified among many companies, collectability is dependent upon the financial stability of each individual company and is influenced by the general economic conditions of the industry. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.
Concentrations of Market Risk. The future results of the Company’s oil and gas operations will be affected by the market prices of oil, natural gas and NGLs. A readily available market for oil, natural gas and NGLs in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of oil, gas and NGLs, the regulatory environment, the economic environment and other regional, national and international economic and political events, none of which can be predicted with certainty.
The Company operates in the exploration, development and production phase of the oil and gas industry. Its receivables include amounts due from purchasers of oil and gas production and amounts due from joint venture partners for their respective portions of operating expenses and exploration and development costs. The Company believes that no single customer or joint venture partner exposes the Company to significant credit risk. While certain of these customers and joint venture partners are affected by periodic downturns in the economy in general or in their specific segment of the natural gas or oil industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations in the long-term. Trade receivables are generally not collateralized. The Company analyzes customers’ and joint venture partners’ historical credit positions and payment histories prior to extending credit.
Concentrations of Credit Risk. Derivative financial instruments that hedge the price of oil, natural gas and NGLs are generally executed with major financial or commodities trading institutions which expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company’s policy is to execute financial derivatives only with major, creditworthy financial institutions. The Company has placed derivative instruments with eight different counterparties, of which all are lenders or affiliates of lenders in the Amended Credit Facility.
The creditworthiness of counterparties is subject to continuing review, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties. Where the counterparty is a lender under the Amended Credit Facility, the counterparty risk is mitigated to the extent that the Company is indebted to such lender under the Amended Credit Facility.
13. Commitments and Contingencies
Lease Financing Obligation. The Company has a Lease Financing Obligation with Bank of America Leasing & Capital, LLC as the lead bank as discussed in Note 5. The aggregate undiscounted minimum future lease payments, including both principal and interest components, are presented below:
Transportation Charges. The Company entered into two firm transportation contracts to provide capacity on natural gas pipeline systems. The remaining term on these contracts is six years. The contracts require the Company to pay transportation charges regardless of the amount of pipeline capacity utilized by the Company. Beginning October 1, 2014, these transportation costs are included in unused commitments expense in the Consolidated Statements of Operations. As a result of the divestitures discussed in Note 4, the Company will likely not utilize the firm capacity on the natural gas pipelines.
The amounts in the table below represent the Company's future minimum transportation charges.
Purchase Commitments. The Company has one take-or-pay purchase agreement for supply of carbon dioxide ("CO2"), which has a total financial commitment of $1.7 million. The CO2 is for use in fracture stimulation operations. Under this contract, the Company is obligated to purchase a minimum monthly volume at a set price. If the Company takes delivery of less than the minimum required amount, the Company is responsible for full payment (deficiency payment) in December 2015.
Lease and Other Commitments. The Company leases office space, vehicles and certain equipment under non-cancelable operating leases. Additionally, the Company has entered into various long-term agreements for telecommunication services.
The Company has entered into a sales throughput contract in the South Altamont area of the Uinta Oil Basin. Under this contract, the Company is obligated to sell and deliver a minimum volume commitment ("MVC") of 450.0 MMcf for the period of December 1, 2014 to November 30, 2015. If the minimum volume is not delivered, the Company must make a deficiency payment in the amount of up to $0.8 million. This contract replaces the initial capital expenditures associated with the connection of South Altamont wells that would otherwise be incurred as connected. As of December 31, 2014, the Company had satisfied approximately 19.3 MMcf of this commitment, resulting in an estimated deficiency payment of up to $0.7 million due December 1, 2015.
Future minimum annual payments under lease and other agreements are as follows:
Litigation. The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the course of ordinary business. It is the opinion of the Company’s management that current claims and litigation involving the Company are not likely to have a material adverse effect on its consolidated balance sheets, cash flows or statements of operations.
14. Guarantor Subsidiaries
In addition to the Amended Credit Facility, the 7.625% Senior Notes, the 7.0% Senior Notes and the Convertible Notes, which are registered securities, are jointly and severally guaranteed on a full and unconditional basis by the Company's 100% owned subsidiaries ("Guarantor Subsidiaries"). Presented below are the Company’s condensed consolidating balance sheets, statements of operations, statements of other comprehensive income (loss) and statements of cash flows, as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.
During the three months ended June 30, 2014, Bill Barrett Corporation, as parent, merged two of the Company's 100% owned subsidiaries, CBM Production Company and GB Acquisition Corporation, into the parent company. The condensed consolidating financial statements reflect the new guarantor structure for all periods presented.
The following condensed consolidating financial statements have been prepared from the Company’s financial information on the same basis of accounting as the Consolidated Financial Statements. Investments in the subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Company and the Guarantor Subsidiaries are reflected in the intercompany eliminations column.
Condensed Consolidating Balance Sheets
Condensed Consolidating Statements of Operations
Condensed Consolidating Statements of Comprehensive Income (Loss)
Condensed Consolidating Statements of Cash Flows
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(In Thousands, Except Per Share Data Unless Otherwise Indicated)
(Unaudited)
Oil and Gas Producing Activities
Costs Incurred. Costs incurred in oil and gas property acquisition, exploration and development activities and related depletion per equivalent unit-of-production were as follows:
(1)
Year ended December 31, 2014 includes $79.0 million related to property acquired through asset exchanges, consisting of $29.3 million of unproved acquisition costs and $49.7 million of proved acquisition costs.
Supplemental Oil and Gas Reserve Information. The reserve information presented below is based on estimates of net proved reserves as of December 31, 2014, 2013 and 2012 that were prepared by internal petroleum engineers in accordance with guidelines established by the SEC and were audited by the Company’s independent petroleum engineering firm NSAI in 2014, 2013 and 2012.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Analysis of Changes in Proved Reserves. The following table sets forth information regarding the Company’s estimated net total proved and proved developed oil and gas reserve quantities:
(1)
The increase in NGL revisions of previous estimates from the year ended 2012 to the year ended 2013 includes the impact of the Company's conversion to three stream production. Prior to 2013, NGL reserves were included in natural gas data, which impacts the comparability for the periods presented.
At December 31, 2014, the Company revised its proved reserves downward by 22.2 MMBoe due to engineering revisions of 14.1 MMBoe and aging of proved undeveloped reserves in the Blacktail Ridge and Lake Canyon areas of the Uinta Basin of 8.1 MMBoe. Pricing for 2014 was $4.35 per MMBtu and $94.99 per barrel of oil compared with pricing for 2013 of $3.67 per MMBtu and $96.91 per barrel of oil, resulting in insignificant pricing revisions. Prices were adjusted by lease for quality, transportation fees and regional price differences.
At December 31, 2013, the Company revised its proved reserves upward by 2.2 MMBoe, excluding pricing revisions. The Company also revised its 2013 proved reserves upward by 0.2 MMBoe, as 2013 pricing was $3.67 per MMBtu and $96.91 per barrel of oil compared with the 2012 pricing of $2.56 per MMBtu and $91.21 per barrel of oil. Prices were adjusted by lease for quality, transportation fees and regional price differences.
At December 31, 2012, the Company revised its proved reserves downward by 15.0 MMBoe, excluding pricing revisions, due primarily to negative engineering revisions related to the 20-acre infill drilling performance at the West Tavaputs area in the Uinta Basin. At December 31, 2012, the Company also revised its 2012 proved reserves downward by 13.9 MMBoe, as 2012 pricing was $2.56 per MMBtu and $91.21 per barrel of oil compared with the 2011 pricing of $3.93 per MMBtu and $92.71 per barrel of oil. Prices were adjusted by lease for quality, transportation fees and regional price differences.
Standardized Measure. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is important for a proper understanding and assessment of the data presented.
For the years ended December 31, 2014, 2013 and 2012, future cash inflows are calculated by applying the 12-month average pricing (as is required by the rules of the Securities and Exchange Commission) of oil and gas relating to the Company’s proved reserves to the year-end quantities of those reserves. For the year ended December 31, 2014, calculations were made using adjusted average prices of $79.96 per Bbl for oil, $34.17 per Bbl for NGLs and $3.79 per MMBtu for gas, as compared to the average benchmark prices of $94.99 per Bbl for oil, $39.65 per Bbl for NGLs and $4.35 per Mcf for gas. For the year ended December 31, 2013, calculations were made using adjusted average prices of $83.35 per Bbl for oil, $29.60 per Bbl for NGLs and $3.14 per MMBtu for gas, as compared to the average benchmark prices of $96.91 per Bbl for oil, $39.75 per Bbl for NGLs and $3.67 per Mcf for gas. For the year ended December 31, 2012, calculations were made using adjusted average prices of $78.85 per Bbl for oil and $3.68 per MMBtu for gas, as compared to the average benchmark prices of $91.21 per Bbl for oil and $2.56 per Mcf for gas. The differences between the average benchmark prices and the adjusted average prices used in the calculation of the standardized measure are attributable to adjustments made for transportation, quality and basis differentials. The Company also records an overhead charge against its future cash flows.
The assumptions used to calculate estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.
Future development and production costs are calculated by estimating the expenditures to be incurred in developing and producing the proved oil, gas and NGL reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are calculated by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil, gas and NGL reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.
The following table presents the standardized measure of discounted future net cash flows related to proved oil, gas and NGL reserves:
The "standardized measure" is the present value of estimated future cash inflows from proved oil, gas and NGL reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10% to reflect timing of future cash flows.
The present value (at a 10% annual discount) of future net cash flows from the Company’s proved reserves is not necessarily the same as the current market value of its estimated oil, gas and NGL reserves. The Company bases the estimated discounted future net cash flows from its proved reserves on prices and costs in effect on the day of estimate in accordance with the applicable accounting guidance. However, actual future net cash flows from its oil, gas and NGL properties will also be affected by factors such as actual prices the Company receives for oil, gas and NGL, the amount and timing of actual production, supply of and demand for oil and natural gas and changes in governmental regulations or taxation.
The timing of both the Company’s production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor the Company uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general.
A summary of changes in the standardized measure of discounted future net cash flows is as follows:
Quarterly Financial Data
The following is a summary of the unaudited quarterly financial data, including income before income taxes, net income and net income per common share for the years ended December 31, 2014 and 2013.
(1)
The decrease in total revenues and expenses in the fourth quarter was primarily due to asset sales during the third quarter. See Note 4 for additional details.