News Column

RAAM GLOBAL ENERGY CO - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

August 13, 2014

The following discussion and analysis should be read in conjunction with our historical consolidated financial statements and the notes to the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2013. Our operating results for the periods discussed may not be indicative of future performance. The following discussion and analysis includes forward-looking statements and should be read in conjunction with "Risk Factors" under Part II, Item 1A of this report, along with the "Cautionary Note Regarding Forward-Looking Statements" at the beginning of this report and our Annual Report on Form 10-K for the year ended December 31, 2013, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.



Overview

We are a privately held oil and natural gas exploration and production company engaged in the exploration, development, production and acquisition of oil and gas properties. Our operations are located in the Gulf of Mexico, offshore Louisiana and onshore Louisiana, Texas, Oklahoma and California. We focus on the development of both conventional and unconventional resource plays. We are currently focused on evaluating and developing our asset base, optimizing our acreage positions and evaluating potential acquisitions, with an emphasis on the development and acquisition of unconventional plays. We are currently seeking partners for joint venture or farm-out arrangements for certain assets located in the Breton Sound area, Ship Shoal area, the Yegua and Cook Mountain region, and the Mid-Continent region. In our onshore conventional plays, we anticipate drilling two additional wells in our Texas Yegua trend. Also, we are currently pursuing permits for a play in California and anticipate drilling two wells there as soon as permitting is complete. We currently have two unconventional plays under lease. One is located in California, and the other is a Mid-Continent play. We anticipate drilling in each of these plays later this year. We have developed a business model of conducting a thorough evaluation of numerous plays, including a detailed geological and geophysical review. When a promising prospect is identified, we conduct core analysis and a very detailed petro physical evaluation in order to fully understand the reserve potential, and we develop a complete economic model to establish the expected returns. Once these evaluations are complete, we create a buy outline for purchasing the undeveloped acreage. We then work to secure a joint venture partner to assist us in developing the acreage. In this model, we would ideally recover a significant portion of our initial investment in the acreage through the arrangement with the joint venture partner. We successfully executed this model in the Bend Arch play during 2013. We subsequently decided to sell our remaining interest in that play to pursue other opportunities; however, we believe it demonstrates the successful execution of our business model. In each of our core areas, we have established a team of experienced geologists and geophysists with extensive experience in the specific area of exploration. We acquired a large library of data including 3-D seismic surveys, well logs, production history, and other relevant data, and we maintain the latest in computer aided exploration hardware and software. Each prospect is subjected to a peer review process, reservoir engineering review, and economic analysis. The combination of having a complete data set, which is evaluated by experienced professionals along with a thorough geological, engineering, and economic review has led to our exploration drilling success. We have employed this system with success in the Gulf of Mexico and onshore in Texas and Louisiana, and we are establishing the same procedures for our Mid-Continent and California unconventional opportunities.



Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

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Table of Contents Recent Developments Financing Updates



The company has hired Moelis & Company to provide financial advisory services regarding the Company's strategic business plan, including financing alternatives to its existing bank facility.

Drilling Updates

A well drilled in Louisiana state waters under the Company's farm-out program was completed in August 2014 and is anticipated to be hooked up and producing by mid-September 2014. The next well in the farm-out program is scheduled to be spud by the end of the third quarter. One of our California wells, which was spud on August 6, 2014, is expected to reach total depth by the end of the third quarter of 2014. A rig has been contracted to drill a well in the Texas Yegua trend and is scheduled to be on location by the end of August 2014. The Company also has another rig contracted to begin drilling in the Texas Yegua trend in early September.



How We Evaluate Our Operations

We use a variety of financial and operational measures to assess our performance. Among these measures are (1) volumes of crude oil and natural gas produced, (2) crude oil and natural gas prices realized, (3) per unit operating and administrative costs and (4) Adjusted EBITDA (as defined below). The following table contains financial and operational data for the three and six month periods ended June 30, 2014 and 2013. Three Months Ended June 30, Six Months Ended June 30, 2014 2013 2014 2013 Average daily production: Oil (Bbl per day) 2,084 2,350 2,097 2,560 Natural gas (Mcf per day) 37,115 38,205 36,153 42,065 Oil equivalents (Boe per day) 8,270 8,718 8,122 9,571 Average prices: (1) Oil ($/Bbl) $ 104.29$ 106.94$ 102.16$ 107.46 Natural gas ($/Mcf) $ 5.20$ 4.55$ 5.26$ 4.27 Oil equivalents ($/Boe) $ 49.62$ 48.75$ 49.79$ 47.50



Production and delivery costs ($/Boe) $ 9.16$ 10.40

$ 9.30$ 9.20 General and administrative expenses ($/Boe) $ 2.32$ 5.89$ 4.38$ 5.56 Net income (loss) attributable to RAAM Global (in thousands) $ (7,349 )$ 1,510$ (15,858 )$ (929 ) Adjusted EBITDA (2) (in thousands) $ 23,901$ 21,220$ 41,460$ 50,775



(1) Average prices presented do not give effect to our derivative activities or

the monetization of oil derivatives during February 2013. Please see Item 1,

Note 5, "Commodity Derivative Instruments and Derivative Activities" for a

discussion of our derivative activities.

(2) Adjusted EBITDA as used herein represents net income before net losses

(gains) on derivatives, net of cash settlements received or paid, interest

expense, income taxes, depreciation, depletion and amortization. We consider

Adjusted EBITDA to be an important indicator for the performance of our

business, but not a measure of performance calculated in accordance with

accounting principles generally accepted in the U.S. ("U.S. GAAP"). 29



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We have included this non-GAAP financial measure because management utilizes

this information for assessing our performance and liquidity and as an

indicator of our ability to make capital expenditures, service debt and

finance working capital requirements. Management believes that Adjusted

EBITDA is a measurement that is commonly used by analysts and some investors

in evaluating the performance and liquidity of companies in our industry. In

particular, we believe that it is useful to our analysts and investors to

understand this relationship because it excludes noncash expense items, such

as depletion. We believe that excluding these transactions allows investors

to meaningfully trend and analyze the performance and liquidity of our core

cash operations. Adjusted EBITDA should not be considered as an alternative

to net income, operating income or any other performance measure derived in

accordance with U.S. GAAP or as an alternative to net cash provided by

operating activities as a measure of our profitability or liquidity. Adjusted

EBITDA has significant limitations, including that it does not reflect our

cash requirements for capital expenditures, contractual commitments, working

capital or debt service. In addition, other companies may calculate Adjusted

EBITDA differently than we do, limiting their usefulness as comparative

measures.

The following table sets forth a reconciliation of net income (loss) as determined in accordance with U.S. GAAP, the most comparable U.S. GAAP measure, to Adjusted EBITDA for the three and six month periods ended June 30, 2014 and 2013. Three Months Ended June 30, Six Months Ended June 30, 2014 2013 2014 2013 In thousands Net income (loss) attributable to RAAM Global $ (7,349 )$ 1,510$ (15,858 )$ (929 ) Net losses (gains) on derivatives, net of cash settlements received or paid 1,897 (7,218 ) 3,251 962 Interest expense 8,223 7,822 16,039 14,587 Depreciation, depletion and amortization 23,387 17,855 41,905 36,181 Income taxes (2,257 ) 1,251 (3,877 ) (26 ) Adjusted EBITDA $ 23,901$ 21,220$ 41,460$ 50,775 30



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Results of Operations

The following table sets forth the unaudited results of operations for the three and six month periods ended June 30, 2014 and 2013 in thousands.

Three Months Ended June 30, Six Months Ended June 30, 2014 2013 2014 2013 Revenues: Gas sales $ 17,560$ 15,806$ 34,435$ 32,492 Oil sales 19,782 22,869 38,769 49,791 Gains (losses) on derivatives, net (3,920 ) 5,726 (8,640 ) (474 ) Total revenues 33,422 44,401 64,564 81,809 Costs and expenses: Production and delivery costs 6,896 8,252 13,667 15,938 Production taxes 2,137 1,820 4,164 3,910 Workover costs 289 802 2,115 1,458 Depreciation, depletion and amortization 23,387 17,855 41,905 36,181 General and administrative expenses 1,744 4,655 6,436 9,630 Total operating expense 34,453 33,384 68,287 67,117 Income (loss) from operations (1,031 ) 11,017 (3,723 ) 14,692 Other income (expenses): Interest expense, net (8,198 ) (7,800 ) (15,988 ) (14,549 ) Other, net 96 (25 ) 722 (147 ) Total other income (expenses) (8,102 ) (7,825



) (15,266 ) (14,696 )

Income (loss) before taxes (9,133 ) 3,192 (18,989 ) (4 ) Income tax provision (benefit) (2,257 ) 1,251 (3,877 ) (26 ) Net income (loss) including noncontrolling interest $ (6,876 )$ 1,941



$ (15,112 )$ 22

Net income attributable to noncontrolling interest (net of tax) 473 431 746 951 Net income (loss) attributable to RAAM Global $ (7,349 )$ 1,510$ (15,858 )$ (929 )



Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

Revenues

Oil and natural gas production. Oil and natural gas production for the three months ended June 30, 2014 decreased to 0.75 MMBoe from 0.79 MMBoe for the three months ended June 30, 2013. During the three months ended June 30, 2014, natural gas production decreased 3% and oil production decreased 11%, resulting in a 5% decrease in Boe production over the three months ended June 30, 2014. Oil and natural gas production decreased because production from new wells and recompletions in both the shallow waters of Louisiana and onshore Texas did not offset normal production declines from our mature wells and production declines due to the formation collapse that led to the shearing of the casing in several of our Texas wells in late second quarter of 2013. 31



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Total revenues. Total revenues for the three months ended June 30, 2014 decreased to $33.4 million from $44.4 million for the three months ended June 30, 2013. Natural gas revenues (exclusive of derivatives) increased $1.8 million or 11% due to higher natural gas prices along with higher production for the three months ended June 30, 2014 as compared to the three months ended June 30, 2013. Natural gas prices increased by 14% period over period, to an average price of $5.20 for the three months ended June 30, 2014 from an average natural gas price of $4.55 for the three months ended June 30, 2013. Oil revenues (exclusive of derivatives) decreased $3.1 million or 13%, over the prior year period due to lower oil volumes and lower oil prices. The average oil price of $104.29 for the three months ended June 30, 2014 represented 2% decrease from the average oil price of $106.94 for the three months ended June 30, 2013 (excluding the effects of derivative activities).



Operating costs and expenses

Production and delivery costs. Production and delivery costs for the three months ended June 30, 2014 decreased to $6.9 million from $8.3 million for the same period in 2013. Production and delivery costs per Boe decreased to $9.16 per Boe for the three months ended June 30, 2014 from $10.40 per Boe for the same period in 2013 primarily as a result of lower production and delivery costs during the second quarter of 2014. In the second quarter of 2014 the Company experienced lower contract pumping services and insurance and labor costs than those during the same period in 2013. Production taxes. Production taxes were $2.1 million for the three months ended June 30, 2014, and $1.8 million for the comparable period in 2013. The Company pays production taxes to state governments at rates specified by geographic location and commodity. The slight increase in production taxes is due primarily to a new onshore well coming online during the quarter. Workover costs. Our workover costs for the three months ended June 30, 2014 decreased to $0.3 million from $0.8 million for the same period in 2013. Workover costs per Boe decreased to $0.38 for the three months ended June 30, 2014 from $1.01 per Boe for the same period in 2013 primarily as a result of decreased workover costs during the second quarter of 2014. Workovers are performed on wells that need certain mechanical changes or enhancements to maintain or increase production. Due to less mechanical needs during the second quarter of 2014, the Company performed less workovers in that period than were necessary during the same period in 2013. Also, workover projects performed during the second quarter of 2014 had lower equipment rental and electric line service costs than those performed during the same period of 2013. Depreciation, depletion and amortization. Depreciation, depletion and amortization for the three months ended June 30, 2014 increased to $23.4 million from $17.9 million for the three months ended June 30, 2013. The depletion rate for the second quarter of 2014 was higher than the depletion rate for the same period in 2013 due to lower future gross revenues at June 30, 2014 resulting from the downward revisions to eliminate the Ewing Banks 920 Project proved undeveloped reserves during the third quarter of 2013. Also, a $5.3 million ceiling test writedown was recorded at June 30, 2014. General and administrative expenses. General and administrative expenses decreased to $1.7 million for the three months ended June 30, 2014 from $4.7 million for the three months ended June 30, 2013. The decrease in general and administrative expenses was mainly due to lower consultant compensation, data processing and repairs and maintenance costs during the second quarter of 2014 as compared to the same period of 2013. Interest expense, net. Net interest expense increased to $8.2 million for the three months ended June 30, 2014, from $7.8 million for the three months ended June 30, 2013 because of higher average interest rates. Debt balances averaged $250.0 million during the three months ended June 30, 2014 and 2013. Interest rates averaged 12.5% and 11.9% during the three months ended June 30, 2014 and 2013, respectively. In the second quarter of 2014, the Company had $250.0 million of senior secured notes outstanding with a 12.5% interest rate. For a portion of the second quarter of 2013, the Company had $200.0 million of senior secured notes outstanding with a 12.5% interest rate and $50.0 million outstanding under the amended revolving credit facility with an average interest rate of 3.2%. 32



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Income tax (benefit) provision. For the three months ended June 30, 2014, the Company recorded an income tax benefit of $2.3 million as compared to income tax expense of $1.3 million for the three months ended June 30, 2013. Income tax (benefit) provision recognized was based on effective tax rate calculations of approximately 24.7% at June 30, 2014 and approximately 39.2% at June 30, 2013. The difference in the rates for the second quarters of 2014 and 2013 is primarily due to the recording of a valuation allowance against deferred tax assets in 2014. The valuation allowance is recorded based on our current assessment that it is more likely than not that certain of our deferred tax assets will not be realized in the foreseeable future.



Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Revenues

Oil and natural gas production. Oil and natural gas production for the six months ended June 30, 2014 decreased to 1.5 MMBoe from 1.7 MMBoe for the six months ended June 30, 2013. During the six months ended June 30, 2014, natural gas production decreased 14% and oil production decreased 18%, resulting in a 15% decrease in Boe production over the six months ended June 30, 2013. Oil and natural gas production decreased because production from new wells and recompletions in both the shallow waters of Louisiana and onshore Texas did not offset normal production declines from our mature wells and production declines due to the formation collapse that led to the shearing of the casing in several of our Texas wells in late second quarter of 2013. Total revenues. Total revenues for the six months ended June 30, 2014 decreased to $64.6 million from $81.8 million for the six months ended June 30, 2013. Natural gas revenues (exclusive of derivatives) increased $1.9 million or 6% due to higher natural gas prices more than offsetting lower natural gas production for the six months ended June 30, 2014 as compared to the six months ended June 30, 2013. Natural gas prices increased by 23% period over period, to an average price of $5.26 for the six months ended June 30, 2014 from an average natural gas price of $4.27 for the six months ended June 30, 2013. Oil revenues (exclusive of derivatives) decreased $11.0 million or 22%, over the prior year period due to lower oil volumes and lower oil prices. The average oil price of $102.16 for the six months ended June 30, 2014 represented a 5% decrease from the average oil price of $107.46 for the six months ended June 30, 2013 (excluding the effects of derivative activities).



Operating costs and expenses

Production and delivery costs. Production and delivery costs for the six months ended June 30, 2014 decreased to $13.7 million from $15.9 million for the same period in 2013. Production and delivery costs per Boe increased to $9.30 per Boe for the six months ended June 30, 2014 from $9.20 per Boe for the same period in 2013 primarily as a result of decreased oil and natural gas production described above in the first half of 2014. During 2014 the Company also experienced lower contract pumping services, insurance, lift boat and labor costs and supplies and tools than those during the same period in 2013. Production taxes. Production taxes were $4.2 million for the six months ended June 30, 2014, and $3.9 million for the comparable period in 2013. The Company pays production taxes to state governments at rates specified by geographic location and commodity. The slight increase in production taxes is due primarily to a new onshore well coming online during the period.



Workover costs. Our workover costs for the six months ended June 30, 2014 increased to $2.1 million from $1.5 million for the same period in 2013. Workover costs per Boe increased to $1.44 for the six months ended June 30, 2014 from $0.84 per Boe for the same period in 2013 primarily as a result of decreased oil and natural gas production described above in the first half of 2014. Workovers are performed on wells that need certain mechanical changes or enhancements to maintain or increase production.

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Due to mechanical needs during the first half of 2014, the Company performed more workovers in that period than were necessary during the same period in 2013. Also, workover projects performed during the first half of 2014 had higher lift boat, contract rig and surface equipment costs than those performed during the same period of 2013. Depreciation, depletion and amortization. Depreciation, depletion and amortization for the six months ended June 30, 2014 increased to $41.9 million from $36.2 million for the six months ended June 30, 2013. The depletion rates for the first and second quarters of 2014 were higher than the depletion rates for the same periods in 2013 due to lower future gross revenues at both March 31, 2014 and June 30, 2014 resulting from the downward revisions to eliminate the Ewing Banks 920 Project proved undeveloped reserves during the third quarter of 2013. Also, a $5.3 million ceiling test writedown was recorded at June 30, 2014. General and administrative expenses. General and administrative expenses decreased to $6.4 million for the six months ended June 30, 2014 from $9.6 million for the six months ended June 30, 2013. The decrease in general and administrative expenses was mainly due to lower consultant compensation, data processing and repairs and maintenance costs during the first half of 2014 as compared to the same period of 2013. Interest expense, net. Net interest expense increased to $16.0 million for the six months ended June 30, 2014, from $14.5 million for the six months ended June 30, 2013 because of higher average interest rates. Debt balances averaged $250.0 million during the six months ended June 30, 2014 and 2013. Interest rates averaged 12.5% and 11.3% during the six months ended June 30, 2014 and 2013, respectively. In the first half of 2014, the Company had $250.0 million of senior secured notes outstanding with a 12.5% interest rate. In the first half of 2013, the Company had $200.0 million of senior secured notes outstanding with a 12.5% interest rate and $50.0 million outstanding under the amended revolving credit facility with an average interest rate of 3.2%. Income tax benefit. For the six months ended June 30, 2014, the Company recorded an income tax benefit of $3.9 million as compared to an income tax benefit of $26,000 for the six months ended June 30, 2013. Income tax benefits recognized were based on effective tax rate calculations of approximately 20.4% at June 30, 2014 and approximately 648% at June 30, 2013. The difference in the rates for the first six months of 2014 and 2013 is primarily due to a change in the expected annual financial results which affected both the federal and state annualized tax rates and the recording of a valuation allowance against deferred tax assets in 2014. The valuation allowance is recorded based on our current assessment that it is more likely than not that certain of our deferred tax assets will not be realized in the foreseeable future.



Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from shareholders, borrowings under our Amended Revolving Credit Facility, debt financings, sales of non-core assets and cash flows from operations. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. We continually monitor potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements.



Capital Expenditures

The Company spent approximately $33 million on capital expenditures during the first six months of 2014. We anticipate spending an additional $30 million on capital expenditures during the remainder of 2014. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, 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 flows and other factors both within and outside our control. 34



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Our total 2014 capital expenditure budget is approximately $63 million, of which approximately $33 million was expended in the first six months of 2014. The Company expects the remaining capital budget of $30 million to consist of:

$4 million for geological and geophysical costs, including leasing; $2 million for Louisiana state water drilling and development; $13 million for onshore conventional drilling and development; $7 million for California drilling and development; and $4 million for projects in progress; recompletions. While we have budgeted $30 million for these purposes for the remainder of 2014, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. To date, our 2014 capital budget has been funded from our cash flows from operations and proceeds from the sale of other non-core assets. We believe our existing cash balance and cash flows from operations should be sufficient to fund the remainder of our 2014 capital expenditure budget. As of June 30, 2014, we had no amounts outstanding under our revolving credit facility and $250.0 million in Notes outstanding. Our revolving credit facility was unavailable at June 30, 2014 due to the Company not being in compliance with the interest coverage ratio. The Company was in compliance with the debt covenants for this facility at June 30, 2014, with the exception of the interest coverage ratio. The covenant specifies that the Company should maintain at least a 2.5 to 1.0 interest coverage ratio for the four immediately preceding consecutive fiscal quarters. For the four immediately preceding fiscal quarters ended June 30, 2014, the Company's interest coverage ratio was 2.3 to 1.0. The Company did not meet this covenant for the four immediately preceding fiscal quarters ended June 30, 2014 due to increased debt balances at a higher average interest rate than during previous periods combined with lower revenues mainly due to decreased oil production and lower oil prices. This covenant breach is an event of default under the credit facility. As a result of this covenant breach, on July 31, 2014 the Company entered into a forbearance agreement with its senior secured lenders under the Amended Revolving Credit Facility (the "Forbearance Agreement"). Pursuant to the Forbearance Agreement, the lenders, as well as the counterparties to certain outstanding hedging agreements with the Company, have agreed to forbear from exercising any rights or remedies that any of them may have, or from initiating or instituting legal proceedings, against the Company or any of the subsidiary guarantors under the Amended Revolving Credit Facility, or from realizing on their security granted in connection with the Credit Agreement, until the earlier of September 30, 2014 or the occurrence of an event of default within the meaning of the Forbearance Agreement. Pursuant to the terms of the Forbearance Agreement, among other provisions, the borrowing base was permanently reduced to zero, thereby preventing additional borrowings under the Amended Revolving Credit Facility. The Company also agreed to maintain $4.0 million in deposit accounts with the administrative agent in connection with the settlement of the outstanding hedging agreements. The Company is currently working to secure new financing; however, there can be no assurance of additional financing being available or on terms acceptable to us. 35



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Consolidated Cash Flows

The table below discloses the net cash provided by (used in) operating activities, investing activities, and financing activities for the six months ended June 30, 2014 and 2013: Six Months Ended June 30, 2014 2013 In thousands



Net cash provided by operating activities $ 21,519$ 45,131

Net cash used in investing activities (36,976 )



(59,946 )

Net cash provided by financing activities 1,529



2,035

Net decrease in cash and cash equivalents $ (13,928 )$ (12,780 )

Cash flows provided by operating activities

Operating activities provided cash totaling $21.5 million during the six months ended June 30, 2014 as compared to cash provided by operating activities of $45.1 million during the six months ended June 30, 2013. The decrease in operating cash flows during the six months ended June 30, 2014 was primarily due to the net loss recorded for the period, the increase in accounts and revenues receivable balances and the decrease in accounts payable balances. Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and natural gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing commodity prices on our financial position, see Part I, Item 3, "Quantitative and Qualitative Disclosures About Market Risk" below.



Cash flows used in investing activities

Investing activities used cash totaling $37.0 million during the six months ended June 30, 2014 as compared to cash used in investing activities of $60.0 million during the same period in 2013. Cash used in investing activities during the six months ended June 30, 2014 decreased as compared to the same period of 2013 primarily because of decreased drilling onshore Texas as well as the joint venture arrangement for drilling in shallow state waters under which the Company has minor working interests for the drilling phases of projects. Also, proceeds from asset sales occurring in the first six months of 2014 and 2013 generated $0.5 million and $17.3 million, respectively, of additional cash which offset capital expenditures during the periods.



Our capital expenditures for drilling, development and acquisition costs during the six month periods ended June 30, 2014 and 2013 are summarized in the following table (in thousands):

Six Months Ended June 30, 2014 2013 Project Area Federal $ 6,191$ 8,184 Shallow State Waters 3,393 34,983



Onshore Texas, Louisiana and Mississippi 17,847 27,617

California, Oklahoma and Mid-Continent 5,575

6,397 Total $ 33,006$ 77,181 36



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Cash flows provided by financing activities

Financing activities provided cash totaling $1.5 million during the six months ended June 30, 2014 as compared to cash provided by financing activities of $2.0 million during the same period in 2013. Cash flows provided by financing activities during the first six months of 2014 consisted of $4.5 million of borrowings for our insurance premium financing, offset partially by payments of $3.0 million on borrowings. Cash flows provided by financing activities during the first six months of 2013 consisted primarily of a $51.5 million issuance of New Notes and $6.8 million in borrowings for our insurance premium financing offset partially by payments of $53.1 million on our revolving credit facility and other borrowings and $1.6 million for shareholder dividends.



Off-Balance Sheet Arrangements

As of June 30, 2014, the Company had no off-balance sheet arrangements or guarantees of third party obligations. The Company has no plans to enter into any off-balance sheet arrangements in the foreseeable future.

Oil and Gas Derivatives

As part of our risk management program, we utilize derivative transactions to reduce the variability in cash flows associated with a portion of our anticipated oil and natural gas production to reduce our exposure to fluctuations in oil and natural gas prices. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions. While the use of these derivative arrangements limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements. In addition, the use of derivative transactions may involve basis risk. The use of derivative transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. All of our derivative transactions are settled based upon reported settlement prices on the NYMEX. At June 30, 2014, on a Boe basis, commodity derivative instruments were in place covering approximately 54% of our projected oil and natural gas sales for 2014 and approximately 22% of our projected oil and natural gas sales for 2015. Approximately 54% of the Company's 2014 natural gas production, approximately 17% of the Company's 2015 natural gas production, approximately 57% of the Company's 2014 oil production, and approximately 37% of the Company's 2015 oil production will yield minimum prices under the contracts as discussed in Item 1, Note 5, "Commodity Derivative Instruments and Derivative Activities." Future oil and natural gas sales prices on other production will fluctuate according to market conditions. As of June 30, 2014, the Company had entered into the following oil derivative instruments: NYMEX Contract Price Swaps Weighted Average Volume in Bbls/Mo Strike Price Period 2014(1) 32,634 $ 90.26 2015 20,945 $ 89.00 (1) Average volume is calculated for the remainder of the 2014 year. 37



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Table of Contents NYMEX Contract Price Sell Put Weighted Average Volume in Bbls/Mo Strike Price Period 2014(1) 10,733 $ 63.60 2015 20,945 $ 70.00 (1) Average volume is calculated for the remainder of the 2014 year. As of June 30, 2014, the Company had entered into the following natural gas derivative instruments: NYMEX Contract Price Swaps Weighted Average Volume in MMBtus/Mo Strike Price Period 2014(1) 569,175 $ 4.02 2015 149,388 $ 4.28



(1) Average volume is calculated for the remainder of the 2014 year.

NYMEX Contract Price Sell Call Buy Call Weighted Average



Weighted Average

Volume in MMBtus/Mo Strike Price Volume in MMBtus/Mo Strike Price Period 2014(1) 312,800 $ 5.00 312,800 $ 4.50 (1) Average volume is calculated for the remainder of the 2014 year. NYMEX Contract Price Sell Put Weighted Average Volume in MMBtus/Mo Strike Price Period 2015 316,430 $ 3.50 Please see Item 1, Note 2, "Basis of Presentation and Significant Accounting Policies" included in Part I for additional discussion regarding the accounting applicable to our derivative program. 38



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Table of Contents Financing Facilities Senior Secured Notes On September 24, 2010, the Company completed an offering of $150.0 million senior secured notes at a coupon rate of 12.5% (the "Original Notes") with a maturity date of October 1, 2015. Interest on the Original Notes is payable in cash semi-annually in arrears on April 1 and October 1 of each year, which commenced on April 1, 2011, to holders of record at the close of business on the preceding March 15 or September 15. Interest on the Original Notes is computed on the basis of a 360-day year of twelve 30-day months. The Original Notes were sold at 99.086% of their face amount and were recorded at their discounted amount, with the discount to be amortized over the life of the notes. The Company used a portion of the net proceeds from the offering to repay all outstanding indebtedness under the Amended Revolving Credit Facility and the remainder of the proceeds was used to fund a portion of our planned capital expenditures for development and drilling. On May 10, 2011, the Company closed an exchange offer registering substantially all of the Original Notes. On July 15, 2011, the Company completed the issuance and sale of $50.0 million aggregate principal amount of additional 12.5% Senior Notes due 2015 (the "Additional Notes," collectively with the Original Notes, the "Existing Notes"). The Additional Notes are additional notes permitted under the indenture dated as of September 24, 2010, pursuant to which the Company initially issued the Original Notes, as supplemented by the First Supplemental Indenture dated as of July 15, 2011. The Additional Notes were sold at 102.5% of their face amount and were recorded at their premium amount, with the premium to be amortized over the life of the notes. The Additional Notes have identical terms, other than the issue date and issue price, and constitute part of the same series as the Original Notes. On November 18, 2011, the Company closed an exchange offer registering all of the Additional Notes. On April 11, 2013, the Company successfully completed the issuance and sale of $50.0 million aggregate principal amount of additional 12.5% Senior Notes due 2015 (the "New Additional Notes," and together with the Original and Additional Notes, the "Notes"). The New Additional Notes are additional notes issued pursuant to the indenture dated as of September 24, 2010, pursuant to which the Company issued the Original and Additional Notes, as supplemented by the First Supplemental Indenture dated as of July 15, 2011 (the "First Supplemental Indenture"), the Second Supplemental Indenture dated as of April 11, 2013 (the "Second Supplemental Indenture") and the Third Supplemental Indenture dated as of April 11, 2013 (the "Third Supplemental Indenture," and together with the Base Indenture, First Supplemental Indenture and the Second Supplemental Indenture, the "Indenture"). The New Additional Notes have identical terms, other than the issue date and issue price, and constitute part of the same series as the Original and Additional Notes. The Company used the net proceeds from the offering to repay existing indebtedness under the Company's Amended Revolving Credit Facility and for general corporate purposes. On November 5, 2013, the Company closed an exchange offer registering all of the New Additional Notes. As of June 30, 2014, a total of $250.0 million notional amount of the Notes was outstanding. The carrying amount of the Notes including unamortized premium and discount was $250.7 million as of June 30, 2014. The Notes are guaranteed on a senior secured basis by each of our existing and future domestic subsidiaries that guarantee indebtedness under our Amended Revolving Credit Facility. The Notes and the guarantees are secured by a security interest in substantially all of our existing and future domestic subsidiaries' (other than certain future unrestricted subsidiaries') assets to the extent they constitute collateral under our Amended Revolving Credit Facility, subject to certain exceptions. Pursuant to an Intercreditor Agreement, the lien securing the Notes is subordinated and junior to liens securing our Amended Revolving Credit Facility.



Amended Revolving Credit Facility

The borrowing base was $50.0 million, and no amounts were drawn at June 30, 2014. Our revolving credit facility was unavailable at June 30, 2014 due to the Company not being in compliance with the interest coverage ratio.

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The Credit Agreement governing the Amended Revolving Credit Facility includes covenants restricting certain of the Company's financial ratios, including its current ratio and a debt coverage ratio, and a limitation on general and administrative expenses. The covenants also include limitations on borrowings, investments and distributions. The Company was in compliance with these debt covenants at June 30, 2014, with the exception of the interest coverage ratio. The covenant specifies that the Company should maintain at least a 2.5 to 1.0 interest coverage ratio for the four immediately preceding consecutive fiscal quarters. For the four immediately preceding fiscal quarters ended June 30, 2014, the Company's interest coverage ratio was 2.3 to 1.0. The Company did not meet this covenant for the four immediately preceding fiscal quarters ended June 30, 2014 due to increased debt balances at a higher average interest rate than during previous periods combined with lower revenues mainly due to decreased oil production and lower oil prices. This covenant breach is an event of default under the credit facility. As a result of this covenant breach, on July 31, 2014 the Company entered into a forbearance agreement with its senior secured lenders under the Amended Revolving Credit Facility. Pursuant to the Forbearance Agreement, the lenders, as well as the counterparties to certain outstanding hedging agreements with the Company, have agreed to forbear from exercising any rights or remedies that any of them may have, or from initiating or instituting legal proceedings, against the Company or any of the subsidiary guarantors under the Amended Revolving Credit Facility, or from realizing on their security granted in connection with the Credit Agreement, until the earlier of September 30, 2014 or the occurrence of an event of default within the meaning of the Forbearance Agreement. Pursuant to the terms of the Forbearance Agreement, among other provisions, the borrowing base was permanently reduced to zero, thereby preventing additional borrowings under the Amended Revolving Credit Facility. The Company also agreed to maintain $4.0 million in deposit accounts with the administrative agent in connection with the settlement of the outstanding hedging agreements. Our obligations under the Amended Revolving Credit Facility are secured by a lien on substantially all of our and our subsidiaries' current and fixed assets (subject to certain exceptions).



Critical Accounting Policies and Estimates

This Quarterly Report on Form 10-Q has been prepared pursuant to the rules and regulations of the SEC applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. GAAP. The preparation of our 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.



There have been no changes to our critical accounting policies from those disclosed in our Form 10-K for the year ended December 31, 2013.


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