TULSA, Okla.--(BUSINESS WIRE)--RAM Energy Resources, Inc. (Nasdaq: RAM) today announced third quarter 2011 financial results and operating highlights, together with a revised non-acquisition capital budget and plans for continuing development of the Company’s Northern Oklahoma Mississippian play.
RAM Reports 3Q 2011 Net Income of $11.8 Million vs. $1.6 Million in 3Q 2010
For the quarter ended September 30, 2011, RAM reported net income of $11.8 million, or $0.15 per share, based on 79.1 million fully diluted weighted average shares outstanding, compared to $1.6 million, or $0.02 per share, on 78.6 million fully diluted shares outstanding in the year-ago quarter.
Modified EBITDA (a non-GAAP measure) was $12.4 million for the 3Q 2011, compared with $12.0 million in last year’s quarter. Similarly, free cash flow (a non-GAAP measure) was $9.0 million, or $0.11 per share, for this year’s third quarter compared to $7.5 million, or $0.10 per share, in last year’s third quarter.
Update to Osage Concession Activity
Drilling of the four vertical wells planned for the third quarter was delayed until late in the quarter due to rig availability. The Cooper #3-35 spudded on September 24, 2011 and drilled to a total depth of 2,380 feet and is currently testing. The Kendrick #2-27 spudded on September 30, 2011 and drilled to a depth of 2,411 feet is waiting on completion. Both the Cooper #3-35 and the Kendrick #2-27 wells were drilled through the Mississippi Chat and Lime formations. Subsequent to quarter’s end, the Ricketts #2-25 spudded on October 7, 2011 and reached a total depth of 2,500 feet on October 10, 2011. This well is currently waiting on completion. Drilling of the fourth well, the Jones #1-33, continues to be delayed pending resolution of an access road to the drill site. Permitting has been approved for the Rickets #3-35 SWD, the Company’s second salt water disposal well in the play. Tentative plans are to drill the Ricketts #3-35 SWD in December of this year depending on rig availability. The addition of the Ricketts #3-35 SWD will add significant disposal capacity for the salt water which is produced in association with the oil and gas from the Mississippian formation.
- Southern Surber Area
The Surber #1-26 continues to produce at rates considerably above the type curve of vertical wells surveyed. After fracture stimulation was applied to the Mississippi Chat formation the well produced at a rate of 108 barrels of oil equivalent per day (BOEPD) in June 2011. As of October 31, 2011 cumulative production from the well was approximately 16,000 barrels of oil equivalent (BOE) and the daily production was approximately 50 BOE.
Testing is currently underway on multiple vertical wells previously drilled, including the Ricketts #2-35, Ricketts #3-26, Surber #1-35 and the Surber #2T. As of October 31, 2011 the four wells are producing a total of approximately 55 BOEPD.
- Central Mashunkashey Area
The Christenson #3-2, which initially tested at 750 thousand cubic feet per day (MCFPD) (125 BOEPD) of natural gas from the Arbuckle formation and subsequently tested natural gas in the Mississippi Dense (Lime) formation, continues to await regulatory authority approval to commingle both zones for additional testing.
- Horizontal Drilling Planned for 2012
The horizontal drilling phase of RAM’s Mississippi oil concession is tentatively planned for early 2012. Phases I and II of the 3-D seismic data set have been merged and cover 56 square miles within the concession. Science gathered from RAM’s first fourteen vertical wells, including information derived from Formation Micro-Imager and dipole sonic logs, and from wellbore coring, has been incorporated into the 3-D data set for identifying future horizontal drilling locations.
In addition to the seismic and science information acquired in the vertical drilling phase, there is considerable horizontal drilling activity in close proximity to the Company’s concession by other private operators in Osage county. A horizontal well three miles directly west has been successfully drilled, tested and is currently waiting on a frac date. Another horizontal well is currently drilling to the south, and a third horizontal well is planned to the north of the Company’s concession.
Third Quarter Results
Crude oil and natural gas sales decreased $2.3 million, or 9%, to $24.1 million for the three months ended September 30, 2011, as compared to $26.5 million for the three months ended September 30, 2010. Excluding for comparison purposes third quarter 2010 production from properties sold by the Company in December 2010, oil and natural gas sales increased by $0.2 million for the three months ended September 30, 2011, as compared to the same period in 2010, as shown in the accompanying table, 2010 Pro Forma Selected Results. This increase was driven by higher commodity prices during the 2011 period, offset by decreased production.
Crude oil and natural gas liquids (NGLs) production in third quarter 2011 was 258,000 barrels, down slightly compared to 270,000 barrels of crude oil and NGLs produced in the second quarter of 2011. Total production in third quarter 2011 was 361,000 BOE, down 33% from 541,000 BOE in the previous year’s quarter. Excluding production in the year ago quarter of 88,000 BOE attributable to properties sold in December 2010, RAM’s production would have decreased by 20% in the current quarter, as shown in the accompanying table, Components of Production Decline, due primarily to normal production declines and the shutting-in of one well in Louisiana in conjunction with a major workover.
The Company’s realized price for crude oil increased 20% to an average of $88.99 per barrel in third quarter 2011 compared with last year’s third quarter average realized price of $74.05 per barrel. In addition, the price of NGLs grew 65% in third quarter 2011, averaging $58.76 per barrel, compared to the average of $35.71 per barrel for last year’s third quarter. Similarly, the Company’s realized price for natural gas rose 2% in third quarter 2011 to an average of $4.14 per Mcf compared to an average of $4.05 per Mcf in the third quarter of 2010. The positive impact from the 37% increase in total average price per BOE in the third quarter 2011 did not fully offset the impact of asset sales and normal production declines, causing crude oil and natural gas sales for the third quarter to decline to $24.1 million compared to $26.5 million in the prior year period.
Derivative activity resulted in a $22.8 million net gain in the third quarter 2011, and as a result, total revenues and other operating income for the quarter rose to $47.0 million. Derivative activity in last year’s third quarter resulted in a $569,000 net gain, raising total revenues and other operating income to $27.1 million in third quarter 2010.
Crude oil and natural gas production expenses were $7.5 million for the quarter ended September 30, 2011, a decrease of $0.6 million, or 7% from the $8.1 million, excluding asset sales, for the quarter ended September 30, 2010. The decrease is primarily due to decreased production volumes, decline in nonrecurring lease operating expenses as well as lower property taxes and utility costs during the 2011 period. Crude oil and natural gas production expenses were $20.77 per BOE compared to $15.84 per BOE for the quarter ended September 30, 2010, an increase of 31%. The increase per BOE is primarily due to the asset sales, as the sold assets in 2010 were predominantly shale gas producing assets which had relatively lower lease operating expenses per BOE. As a percentage of crude oil and natural gas sales, crude oil and natural gas production expenses were 31% for the quarter ended September 30, 2011, as compared to 32% for the quarter ended September 30, 2010. This decrease is due to the decline in production expenses as well as higher commodity prices in the 2011 period.
Excluding asset sales, production taxes for the quarter ended September 30, 2011 were $1.4 million, essentially flat with the prior year period. As a percentage of crude oil and natural gas sales, crude oil and natural gas production taxes were approximately 6% for each of the quarters ended September 30, 2011 and 2010. For the quarter ended September 30, 2011, general and administrative expense was $3.1 million, compared to $2.9 million for the quarter ended September 30, 2010, an increase of $0.2 million, or 6%. The increase was primarily due to higher employee related costs in the 2011 period.
Nine Month 2011 Results
Crude oil and natural gas sales decreased $5.5 million, or 7%, to $78.0 million for the nine months ended September 30, 2011, as compared to $83.5 million for the same period in 2010. Excluding asset sales, crude oil and natural gas sales increased $3.3 million for the nine months ended September 30, 2011 as compared to the same period in 2010. This increase was driven primarily by higher commodity prices during the 2011 period. Nine month production volumes decreased 32% compared to the same period last year. Excluding asset sales, production volumes would have decreased 17% as compared to the same period last year primarily due to normal production declines and the shutting-in of one Louisiana well for a major workover.
Average realized sales prices for crude oil and NGLs increased substantially for the nine months ended September 30, 2011, as compared to the same period in 2010. The positive impact from the 37% increase in total average price per BOE in the first nine months of 2011 did not fully offset the impact of asset sales and normal production declines, causing crude oil and natural gas sales for the first nine months of 2011 to decline to $78.0 million compared to $83.5 million in the same period in 2010. Net income for the nine months ended September 30, 2011 was $10.8 million, or $0.14 per share compared to $6.7 million, or $0.09 per share, compared to the year ago quarter. Modified EBITDA (a non-GAAP measure) was $37.0 million for the nine months ended September 30, 2011 compared with $40.2 million for the same nine month period in 2010. Similarly, free cash flow for the first nine months of 2011 totaled $24.4 million, or $0.31 per share, compared with $26.0 million, or $0.33 per share, for the nine month period ending September 30, 2010.
Long-Term Debt and Liquidity
At September 30, 2011, RAM’s outstanding borrowings under its credit facility totaled $200.0 million, including $75.0 million outstanding under its second lien term loan and $125.0 million drawn on its revolver, which is currently subject to a $150.0 million borrowing base. Availability under the revolving credit facility at September 30, 2011 was $25.0 million. Total outstanding borrowings under the credit facility at September 30, 2010 totaled $246.8 million.
Interest expense for third quarter 2011 was $3.6 million compared to $5.8 million in the year-ago quarter. The decrease is due to lower interest rates under the Company’s new credit facility completed in first quarter 2011 and lower average outstanding borrowings during this year’s quarter. The blended interest rate on borrowings was 6.2% at September 30, 2011 compared to 8.2% at September 30, 2010.
Capital Expenditures and Revised Plans for 2011
During the nine months ended September 30, 2011, capital expenditures were $19.6 million relating to crude oil and natural gas operations, of which $9.2 million was allocated to developmental drilling and recompletions, $5.4 million was allocated to exploration, including leasehold acquisition, seismic and exploratory drilling, and $5.0 million was for geological, geophysical, contingencies, and capitalized general and administrative costs.
The Company has revised its 2011 non-acquisition capital budget to $27.5 million , as follows:
- developmental drilling and recompletions ($13.5 million);
- exploration, including leasehold acquisition, seismic and exploratory drilling ($7.0 million); and
- geological, geophysical, contingencies, and capitalized general and administrative costs ($7.0 million).
In the revised 2011 non-acquisition capital budget for developmental drilling and recompletions, $7.9 million has been allocated to continued development of the Electra/Burkburnett area, $2.8 million for recompletions in RAM’s Louisiana properties, $0.8 million for recompletions in the South Texas properties and $2.0 million for reworking and production enhancement operations in other fields including the Fitts and Allen fields in Oklahoma.
RAM is forecasting production guidance of 1.5 million BOE for 2011.
RAM to Webcast Third Quarter 2011 Conference Call
The Company’s teleconference call to review second quarter results will be broadcast live on a listen-only basis over the internet on Monday, November 7, 2011 at 11:00 a.m. Eastern Time. The full text of the earnings release will be available on the Company’s website at ramenergy.com.
Access:
RAM Energy website: The conference call will be simultaneously webcast and can be accessed through the Investor Relations / Events & Presentations tab of the Company’s website at ramenergy.com.
Dial-in: The conference call may also be accessed by dialing (877)645-6210 (domestic) or (970)315-0430 (international) and providing the conference call ID number “22633054” to the operator.
Replay: A replay of the conference call will be available until November 14, 2011 by dialing toll-free (855)859-2056 and referencing the ID number “22633054”. The webcast call will be posted to the Company’s website following the call’s completion.
Forward-Looking Statements
This release includes certain statements that may be deemed to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements in this release, other than statements of historical facts, which address targets or plans for borrowing availability, and events or developments that the Company expects or believes, are forward-looking statements. Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. Factors that could cause actual results to differ materially from those in forward-looking statements include oil and gas prices, exploitation and exploration successes, actions taken and to be taken by the government as a result of political and economic conditions, continued availability of capital and financing, and general economic, market or business conditions as well as other risk factors described from time to time in the Company’s filings with the SEC. The Company assumes no obligation to update publicly such forward-looking statements, whether as a result of new information, future events or otherwise.
About RAM Energy
RAM Energy Resources, Inc. is an independent energy Company engaged in the acquisition, exploitation, exploration, and development of oil and natural gas properties and the marketing of crude oil and natural gas. Company headquarters are in Tulsa, Oklahoma, and its common shares are traded on the Nasdaq under the symbol RAM. For additional information, visit the Company website at ramenergy.com.
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RAM Energy Resources, Inc. Condensed Consolidated Balance Sheets (in thousands, except share and per share amounts) |
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| September 30, | December 31, | |||||||||
| 2011 | 2010 | |||||||||
| (unaudited) | ||||||||||
| ASSETS | ||||||||||
| CURRENT ASSETS: | ||||||||||
| Cash and cash equivalents | $ | 44 | $ | 37 | ||||||
| Accounts receivable: | ||||||||||
| Oil and natural gas sales, net of allowance of $50 ($50 at December 31, 2010) | 8,394 | 9,797 | ||||||||
| Joint interest operations, net of allowance of $479 ($479 at December 31, 2010) | 443 | 631 | ||||||||
| Other, net of allowance of $11 ($48 at December 31, 2010) | 452 | 155 | ||||||||
| Derivative assets | 5,070 | 1,340 | ||||||||
| Prepaid expenses | 540 | 1,657 | ||||||||
| Deferred tax asset | - | 3,526 | ||||||||
| Inventory | 3,883 | 3,382 | ||||||||
| Other current assets | 537 | 4 | ||||||||
| Total current assets | 19,363 | 20,529 | ||||||||
| PROPERTIES AND EQUIPMENT, AT COST: | ||||||||||
| Proved oil and natural gas properties and equipment, using full cost accounting | 708,984 | 689,472 | ||||||||
| Other property and equipment | 10,471 | 10,072 | ||||||||
|
|
719,455 | 699,544 | ||||||||
| Less accumulated depreciation, amortization and impairment | (505,179 | ) | (489,634 | ) | ||||||
| Total properties and equipment | 214,276 | 209,910 | ||||||||
| OTHER ASSETS: | ||||||||||
| Deferred tax asset | 26,289 | 31,001 | ||||||||
| Derivative assets | 8,125 | - | ||||||||
| Deferred loan costs, net of accumulated amortization of $716 ($5,012 at December 31, 2010) | 6,287 | 2,609 | ||||||||
| Other | 988 | 952 | ||||||||
| Total assets | $ | 275,328 | $ | 265,001 | ||||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||||
| CURRENT LIABILITIES: | ||||||||||
| Accounts payable: | ||||||||||
| Trade | $ | 10,361 | $ | 17,149 | ||||||
| Oil and natural gas proceeds due others | 8,924 | 9,414 | ||||||||
| Other | 3 | 452 | ||||||||
| Accrued liabilities: | ||||||||||
| Compensation | 1,524 | 1,948 | ||||||||
| Interest | 475 | 2,448 | ||||||||
| Income taxes | 318 | 699 | ||||||||
| Other | 97 | 10 | ||||||||
| Deferred tax liability | 2,891 | - | ||||||||
| Derivative liabilities | 264 | - | ||||||||
| Asset retirement obligations | 367 | 639 | ||||||||
| Long-term debt due within one year | 146 | 127 | ||||||||
| Total current liabilities | 25,370 | 32,886 | ||||||||
| DERIVATIVE LIABILITIES | 303 | 203 | ||||||||
| LONG-TERM DEBT | 200,252 | 196,965 | ||||||||
| ASSET RETIREMENT OBLIGATIONS | 31,968 | 30,770 | ||||||||
| OTHER LONG-TERM LIABILITIES | 10 | 10 | ||||||||
| COMMITMENTS AND CONTINGENCIES | ||||||||||
| STOCKHOLDERS' EQUITY : | ||||||||||
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Common stock, $0.0001 par value, 100,000,000 shares authorized, 83,341,299 and 82,597,829 shares issued, 79,067,298 and 78,386,983 shares outstanding at September 30, 2011 and December 31, 2010, respectively |
8 | 8 | ||||||||
| Additional paid-in capital | 228,616 | 226,042 | ||||||||
| Treasury stock - 4,274,001 shares (4,210,846 shares at December 31, 2010) at cost | (7,093 | ) | (6,976 | ) | ||||||
| Accumulated deficit | (204,106 | ) | (214,907 | ) | ||||||
| Stockholders' equity | 17,425 | 4,167 | ||||||||
| Total liabilities and stockholders' equity | $ | 275,328 | $ | 265,001 | ||||||
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RAM Energy Resources, Inc. Condensed Consolidated Statements of Operations (in thousands, except share and per share amounts) (unaudited) |
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| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||
| REVENUES AND OTHER OPERATING INCOME: | ||||||||||||||||||
| Oil and natural gas sales | ||||||||||||||||||
| Oil | $ | 18,955 | $ | 18,290 | $ | 62,150 | $ | 56,898 | ||||||||||
| Natural gas | 2,548 | 4,923 | 8,252 | 16,170 | ||||||||||||||
| NGLs | 2,644 | 3,250 | 7,582 | 10,461 | ||||||||||||||
| Total oil and natural gas sales | 24,147 | 26,463 | 77,984 | 83,529 | ||||||||||||||
| Realized gains (losses) on derivatives | 76 | (1,213 | ) | (1,186 | ) | (2,818 | ) | |||||||||||
| Unrealized gains on derivatives | 22,744 | 1,782 | 18,519 | 6,136 | ||||||||||||||
| Other | 39 | 51 | 124 | 125 | ||||||||||||||
| Total revenues and other operating income | 47,006 | 27,083 | 95,441 | 86,972 | ||||||||||||||
| OPERATING EXPENSES: | ||||||||||||||||||
| Oil and natural gas production taxes | 1,391 | 1,518 | 4,280 | 4,565 | ||||||||||||||
| Oil and natural gas production expenses | 7,499 | 8,571 | 24,048 | 25,153 | ||||||||||||||
| Depreciation and amortization | 5,185 | 6,782 | 15,654 | 20,387 | ||||||||||||||
| Accretion expense | 409 | 452 | 1,223 | 1,288 | ||||||||||||||
| Share-based compensation | 872 | 813 | 2,227 | 2,284 | ||||||||||||||
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General and administrative, overhead and other expenses, net of operator's overhead fees |
3,100 | 2,932 | 10,913 | 10,694 | ||||||||||||||
| Total operating expenses | 18,456 | 21,068 | 58,345 | 64,371 | ||||||||||||||
| Operating income | 28,550 | 6,015 | 37,096 | 22,601 | ||||||||||||||
| OTHER INCOME (EXPENSE): | ||||||||||||||||||
| Interest expense | (3,637 | ) | (5,767 | ) | (13,750 | ) | (17,116 | ) | ||||||||||
| Interest income | 1 | 20 | 4 | 24 | ||||||||||||||
| Loss on interest rate derivatives | (203 | ) | - | (698 | ) | - | ||||||||||||
| Other income (expense) | 181 | (268 | ) | (572 | ) | 293 | ||||||||||||
| INCOME BEFORE INCOME TAXES | 24,892 | - | 22,080 | 5,802 | ||||||||||||||
| INCOME TAX PROVISION (BENEFIT) | 13,116 | (1,564 | ) | 11,279 | (909 | ) | ||||||||||||
| Net income | $ | 11,776 | $ | 1,564 | $ | 10,801 | $ | 6,711 | ||||||||||
| BASIC INCOME PER SHARE | $ | 0.15 | $ | 0.02 | $ | 0.14 | $ | 0.09 | ||||||||||
| BASIC WEIGHTED AVERAGE SHARES OUTSTANDING | 79,086,261 | 78,633,535 | 78,762,799 | 78,361,299 | ||||||||||||||
| DILUTED INCOME PER SHARE | $ | 0.15 | $ | 0.02 | $ | 0.14 | $ | 0.09 | ||||||||||
| DILUTED WEIGHTED AVERAGE SHARES OUTSTANDING | 79,086,261 | 78,633,535 | 78,762,799 | 78,361,299 | ||||||||||||||
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RAM Energy Resources, Inc. Condensed Consolidated Statements of Cash Flows (in thousands) (unaudited) |
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| Nine months ended September 30, | ||||||||||||
| 2011 | 2010 | |||||||||||
| OPERATING ACTIVITIES: | ||||||||||||
| Net income | $ | 10,801 | $ | 6,711 | ||||||||
| Adjustments to reconcile net income to net cash provided by operating activities- | ||||||||||||
| Depreciation and amortization | 15,654 | 20,387 | ||||||||||
| Amortization of deferred loan costs | 3,325 | 1,566 | ||||||||||
| Non-cash interest | 362 | 2,336 | ||||||||||
| Accretion expense | 1,223 | 1,288 | ||||||||||
| Unrealized gain on commodity derivatives, net of premium amortization | (16,947 | ) | (3,859 | ) | ||||||||
| Unrealized loss on interest rate derivatives | 556 | - | ||||||||||
| Deferred income tax provision (benefit) | 11,129 | (933 | ) | |||||||||
| Share-based compensation | 2,227 | 2,284 | ||||||||||
| Gain on disposal of other property and equipment | (22 | ) | (38 | ) | ||||||||
| Other income | - | (574 | ) | |||||||||
| Changes in operating assets and liabilities- | ||||||||||||
| Accounts receivable | 1,293 | 3,023 | ||||||||||
| Prepaid expenses, inventory and other assets | 49 | 1,598 | ||||||||||
| Derivative premiums | 4,889 | (3,738 | ) | |||||||||
| Accounts payable and proceeds due others | (7,681 | ) | 1,603 | |||||||||
| Accrued liabilities and other | (2,386 | ) | (1,717 | ) | ||||||||
| Income taxes payable | (381 | ) | (473 | ) | ||||||||
| Asset retirement obligations | (278 | ) | (161 | ) | ||||||||
| Total adjustments | 13,012 | 22,592 | ||||||||||
| Net cash provided by operating activities | 23,813 | 29,303 | ||||||||||
| INVESTING ACTIVITIES: | ||||||||||||
| Payments for oil and natural gas properties and equipment | (19,600 | ) | (27,476 | ) | ||||||||
| Proceeds from sales of oil and natural gas properties | 462 | 478 | ||||||||||
| Payments for other property and equipment | (503 | ) | (721 | ) | ||||||||
| Proceeds from sales of other property and equipment | 11 | 4 | ||||||||||
| Net cash used in investing activities | (19,630 | ) | (27,715 | ) | ||||||||
| FINANCING ACTIVITIES: | ||||||||||||
| Payments on long-term debt | (235,222 | ) | (37,618 | ) | ||||||||
| Proceeds from borrowings on long-term debt | 238,166 | 36,261 | ||||||||||
| Payments for deferred loan costs | (7,003 | ) | - | |||||||||
| Stock repurchased | (117 | ) | (331 | ) | ||||||||
| Net cash used in financing activities | (4,176 | ) | (1,688 | ) | ||||||||
| INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 7 | (100 | ) | |||||||||
| CASH AND CASH EQUIVALENTS, beginning of period | 37 | 129 | ||||||||||
| CASH AND CASH EQUIVALENTS, end of period | $ | 44 | $ | 29 | ||||||||
| SUPPLEMENTAL CASH FLOW INFORMATION: | ||||||||||||
| Cash paid for income taxes | $ | 531 | $ | 616 | ||||||||
| Cash paid for interest | $ | 12,036 | $ | 13,518 | ||||||||
| DISCLOSURE OF NON CASH INVESTING AND FINANCING ACTIVITIES: | ||||||||||||
| Asset retirement obligations | $ | (23 | ) | $ | 147 | |||||||
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RAM Energy Resources, Inc. Production by Area |
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| Texas | Oklahoma | Louisiana | Other | Total | |||||||||
| Three Months Ended September 30, 2011 | |||||||||||||
| Aggregate net Production | |||||||||||||
| Oil (MBbls) | 116 | 76 | 14 | 7 | 213 | ||||||||
| NGLs (MBbls) | 37 | 5 | - | 3 | 45 | ||||||||
| Natural Gas (MMcf) | 363 | 99 | 119 | 34 | 615 | ||||||||
| MBoe | 214 | 98 | 34 | 15 | 361 | ||||||||
| Texas | Oklahoma | Louisiana | Other | Total | |||||||||
| Three Months Ended September 30, 2010 | |||||||||||||
| Aggregate net Production | |||||||||||||
| Oil (MBbls) | 134 | 81 | 23 | 9 | 247 | ||||||||
| NGLs (MBbls) | 85 | 2 | - | 4 | 91 | ||||||||
| Natural Gas (MMcf) | 802 | 208 | 167 | 38 | 1,215 | ||||||||
| MBoe | 353 | 118 | 51 | 19 | 541 | ||||||||
| Change in MBoe | (139) | (20) | (17) | (4) | (180) | ||||||||
| % change in MBoe | -39.4% | -16.9% | -33.3% | -21.1% | -33.3% | ||||||||
| Texas | Oklahoma | Louisiana | Other | Total | |||||||||
| Nine Months Ended September 30, 2011 | |||||||||||||
| Aggregate net Production | |||||||||||||
| Oil (MBbls) | 369 | 224 | 46 | 22 | 661 | ||||||||
| NGLs (MBbls) | 116 | 10 | - | 10 | 136 | ||||||||
| Natural Gas (MMcf) | 1,219 | 286 | 377 | 103 | 1,985 | ||||||||
| MBoe | 688 | 282 | 109 | 49 | 1,128 | ||||||||
| Texas | Oklahoma | Louisiana | Other | Total | |||||||||
| Nine Months Ended September 30, 2010 | |||||||||||||
| Aggregate net Production | |||||||||||||
| Oil (MBbls) | 425 | 244 | 62 | 26 | 757 | ||||||||
| NGLs (MBbls) | 262 | 7 | - | 11 | 280 | ||||||||
| Natural Gas (MMcf) | 2,440 | 644 | 514 | 116 | 3,714 | ||||||||
| MBoe | 1,094 | 358 | 148 | 56 | 1,656 | ||||||||
| Change in MBoe | (406) | (76) | (39) | (7) | (528) | ||||||||
| % change in MBoe | -37.1% | -21.2% | -26.4% | -12.5% | -31.9% | ||||||||
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RAM Energy Resources, Inc. Components of Production Decline (unaudited) |
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| Three months ended | Nine months ended | ||||||||||
| September 30 | September 30 | ||||||||||
| (MBoe) | (MBoe) | ||||||||||
| Total production, 2010 | 541 | 1,656 | |||||||||
| Declines due to: | |||||||||||
| RAM Texas and Oklahoma gas properties sold in 2010 | (88) | (293) | |||||||||
| Natural production declines in South Texas gas production | (56) | (128) | |||||||||
| Louisiana well shut-in | (10) | (27) | |||||||||
| Other | (26) | (80) | |||||||||
| Total declines | (180) | (528) | |||||||||
| Total production, 2011 | 361 | 1,128 | |||||||||
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2010 Pro Forma Selected Results Excluding Sold Properties (a) (unaudited) |
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| Three months ended September 30, 2010 | ||||||||||||
| Sold | ||||||||||||
| Actual | Assets | Pro Forma | ||||||||||
| Oil and natural gas sales (in thousands): | ||||||||||||
| Oil | $ | 18,290 | $ | 280 | $ | 18,010 | ||||||
| Natural gas | 4,923 | 1,127 | 3,796 | |||||||||
| NGLs | 3,250 | 1,102 | 2,148 | |||||||||
| Total oil and natural gas sales | $ | 26,463 | $ | 2,509 | $ | 23,954 | ||||||
| Production expenses (in thousands): | ||||||||||||
| Oil and natural gas production taxes | $ | 1,518 | $ | 127 | $ | 1,391 | ||||||
| Oil and natural gas production expenses | $ | 8,571 | $ | 473 | $ | 8,098 | ||||||
| Production volumes (MBoe): | ||||||||||||
| Texas | 353 | 73 | 280 | |||||||||
| Oklahoma | 118 | 15 | 103 | |||||||||
| Other | 70 | - | 70 | |||||||||
| Total production | 541 | 88 | 453 | |||||||||
| Nine months ended September 30, 2010 | ||||||||||||
| Sold | ||||||||||||
| Actual | Assets | Pro Forma | ||||||||||
| Oil and natural gas sales (in thousands): | ||||||||||||
| Oil | $ | 56,898 | $ | 957 | $ | 55,941 | ||||||
| Natural gas | 16,170 | 4,001 | 12,169 | |||||||||
| NGLs | 10,461 | 3,875 | 6,586 | |||||||||
| Total oil and natural gas sales | $ | 83,529 | $ | 8,833 | $ | 74,696 | ||||||
| Production expenses (in thousands): | ||||||||||||
| Oil and natural gas production taxes | $ | 4,565 | $ | 380 | $ | 4,185 | ||||||
| Oil and natural gas production expenses | $ | 25,153 | $ | 1,418 | $ | 23,735 | ||||||
| Production volumes (MBoe): | ||||||||||||
| Texas | 1,094 | 244 | 850 | |||||||||
| Oklahoma | 358 | 49 | 309 | |||||||||
| Other | 204 | - | 204 | |||||||||
| Total production | 1,656 | 293 | 1,363 | |||||||||
| (a) | In December 2010 RAM sold assets in Texas and Oklahoma for net proceeds, including post closing adjustments, of $48.8 million. The table above provides actual and pro forma results for the three and nine months ending September 30, 2010 to assist our description of results of operations. |
|
RAM Energy Resources, Inc. Production and Prices Summary |
||||||||||
| Three Months Ended | Nine Months Ended | |||||||||
| September 30, 2011 | September 30, 2011 | |||||||||
| Production volumes: | ||||||||||
| Oil (MBbls) | 213 | 661 | ||||||||
| NGL (MBbls) | 45 | 136 | ||||||||
| Natural gas (MMcf) | 615 | 1,985 | ||||||||
| Total (MBoe) | 361 | 1,128 | ||||||||
| Average sale prices received: | ||||||||||
| Oil (per Bbl) | $ | 88.99 | $ | 94.02 | ||||||
| NGL (per Bbl) | $ | 58.76 | $ | 55.75 | ||||||
| Natural gas (per Mcf) | $ | 4.14 | $ | 4.16 | ||||||
| Total per Boe | $ | 66.89 | $ | 69.13 | ||||||
| Cash effect of derivative contracts: | ||||||||||
| Oil (per Bbl) | $ | (0.34 | ) | $ | (4.61 | ) | ||||
| NGL (per Bbl) | $ | - | $ | - | ||||||
| Natural gas (per Mcf) | $ | 0.24 | $ | 0.94 | ||||||
| Total per Boe | $ | 0.21 | $ | (1.05 | ) | |||||
| Average prices computed after cash effect of settlement of derivative contracts: | ||||||||||
| Oil (per Bbl) | $ | 88.65 | $ | 89.41 | ||||||
| NGL (per Bbl) | $ | 58.76 | $ | 55.75 | ||||||
| Natural gas (per Mcf) | $ | 4.38 | $ | 5.10 | ||||||
| Total per Boe | $ | 67.10 | $ | 68.08 | ||||||
| Expenses (per Boe): | ||||||||||
| Oil and natural gas production taxes | $ | 3.85 | $ | 3.79 | ||||||
| Oil and natural gas production expenses | $ | 20.77 | $ | 21.32 | ||||||
| Amortization of full cost pool | $ | 13.69 | $ | 13.22 | ||||||
| General and administrative | $ | 8.59 | $ | 9.67 | ||||||
| Cash interest | $ | 9.22 | $ | 10.67 | ||||||
| Cash taxes | $ | 0.14 | $ | 0.47 | ||||||
|
RAM Energy Resources, Inc. |
|
Modified EBITDA and Free Cash Flow |
|
(non-GAAP measures) |
|
(unaudited) |
Non-GAAP Financial Measures
Modified EBITDA, a non-GAAP measure, is determined by adding the following to net income (loss): interest expense, income taxes, depreciation, amortization, accretion, share-based compensation, mark-to-market affect of legal settlements, unrealized gains or losses on derivatives. Free cash flow is also a non-GAAP measure representing Modified EBITDA after adjustments for the cash portion of interest and income taxes. These non-GAAP measures are presented because management believes it is a useful adjunct to cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). These non-GAAP measures are widely accepted as financial indicators of an oil and gas Company’s ability to generate cash used to internally fund exploration and development activities and fund debt service costs. These non-GAAP measures are not a measure of financial performance under GAAP and should not be considered as an alternative to cash provided (used) by operating, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity.
|
$000s, except per share amounts |
|||||||||||||||||||||
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||
| 9/30/2011 | 9/30/2010 | 9/30/2011 | 9/30/2010 | ||||||||||||||||||
| Modified EBITDA: | |||||||||||||||||||||
| Net income | $ | 11,776 | $ | 1,564 | $ | 10,801 | $ | 6,711 | |||||||||||||
| Plus: Interest expense | $ | 3,302 | $ | 4,452 | $ | 9,977 | $ | 13,214 | |||||||||||||
| Plus: PIK interest | $ | - | $ | 793 | $ | 448 | $ | 2,336 | |||||||||||||
| Plus: Amortization of deferred loan costs | $ | 335 | $ | 522 | $ | 3,325 | $ | 1,566 | |||||||||||||
| Plus: Depreciation, amortization and accretion | $ | 5,594 | $ | 7,234 | $ | 16,877 | $ | 21,675 | |||||||||||||
| Plus: Share-based compensation | $ | 872 | $ | 813 | $ | 2,227 | $ | 2,284 | |||||||||||||
| Plus: Income tax provision (benefit) | $ | 13,116 | $ | (1,564 | ) | $ | 11,279 | $ | (909 | ) | |||||||||||
| Plus: MTM legal settlement | $ | - | $ | (24 | ) | $ | - | $ | (574 | ) | |||||||||||
| Less: Unrealized gain on derivatives | $ | (22,606 | ) | $ | (1,782 | ) | $ | (17,963 | ) | $ | (6,136 | ) | |||||||||
| Modified EBITDA | $ | 12,389 | $ | 12,008 | $ | 36,971 | $ | 40,167 | |||||||||||||
| Less: | |||||||||||||||||||||
| Cash paid for interest | $ | 3,330 | $ | 4,411 | $ | 12,036 | $ | 13,518 | |||||||||||||
| Cash paid for income tax | $ | 50 | $ | 51 | $ | 531 | $ | 616 | |||||||||||||
| Free cash flow | $ | 9,009 | $ | 7,546 | $ | 24,404 | $ | 26,033 | |||||||||||||
| Weighted average shares outstanding - basic | 79,086 | 78,634 | 78,763 | 78,361 | |||||||||||||||||
| Weighted average shares outstanding - diluted | 79,086 | 78,634 | 78,763 | 78,361 | |||||||||||||||||
| Free cash flow per share - basic | $ | 0.11 | $ | 0.10 | $ | 0.31 | $ | 0.33 | |||||||||||||
| Free cash flow per share - diluted | $ | 0.11 | $ | 0.10 | $ | 0.31 | $ | 0.33 | |||||||||||||