Miller Energy Resources Reports Third Quarter Results

KNOXVILLE, TN--(Marketwired - Mar 12, 2014) - Miller Energy Resources, Inc. ("Miller") (NYSE: MILL) reported its results today for the third quarter of fiscal 2014, which ended January 31, 2014. Total revenues for the quarter were $16.6 million compared to $8.0 million in the third quarter of the prior fiscal year, primarily driven by a 174% increase in net production, from 82,327 BOE to 225,377 BOE, over that same period. Loss before income taxes was $5.3 million for the third quarter of fiscal 2014, compared to a loss before income taxes of $9.3 million for the third quarter of fiscal 2013. Adjusted EBITDA for the third quarter of fiscal 2014 was $4.3 million, compared to an adjusted EBITDA loss of $0.8 million in the third quarter of fiscal 2013.

"Our production reached another all-time high this quarter as we nearly tripled our oil production in Alaska as compared to the third quarter of fiscal 2013. With the addition of the Sword #1 well, the recent closing of the new financing with Apollo and Highbridge and the closing of the North Fork acquisition, we have continued to execute our operational and financial plans to increase production, revenue and cash flows," said Scott M. Boruff, Miller's Chief Executive Officer. "In addition, we saw substantial increases in our proved developed reserve volumes and corresponding PV-10 values in a new reserve report by Ryder Scott Company, primarily as a result of our reworks on the Osprey platform and the drilling of our Sword #1 well."

"We continue to focus on our aggressive drilling program in Alaska, where we have drilling rigs at work on our WMRU-2B and RU-9 oil wells, and our WMRU-8 oil well is currently being brought online. We have also closed the acquisition of the North Fork Unit, and are seeking the needed regulatory approval to close the acquisition of its associated pipeline. As a result of this transaction, we have increased our net production, drilling locations, and wellbore diversification. We are excited about our recent successes and our plans to continue to grow our company's production and shareholder value," Mr. Boruff concluded.

Third Quarter Highlights

• Total revenues were $16.6 million for the third quarter of fiscal 2014 compared to $8.0 million in the third quarter of fiscal 2013 primarily due to increased production.
  
  
• Our gross margin percentage on oil and natural gas sales increased to 65% for the third quarter of fiscal 2014 compared with 40% for the third quarter of fiscal 2013, due to our low variable operating costs.
  
  
• Average realized oil prices declined 4% to $94.58 per barrel in the third quarter of fiscal 2014 compared with $98.77 in the third quarter of fiscal 2013.
  
  
• Net production, excluding fuel gas, increased by 174% to 225,377 BOE for the third quarter of fiscal 2014 compared with 82,327 BOE in the third quarter of fiscal 2013. The increase in production was primarily due to increased production from RU-1A and RU-7 and new production coming online in fiscal 2014 from our RU-2A and RU-5B oil sidetracks and our Sword #1 oil well.
  
  
• Invested $28.3 million in capital expenditures during the third quarter of fiscal 2014, primarily to accelerate oil and gas development opportunities in Alaska.
  
  

Subsequent to the end of the third quarter of fiscal 2014, we refinanced our prior credit facility and entered into a new credit agreement with Apollo Investment Corporation and Highbridge Principal Strategies. The new facility provides for a $175 million term credit facility at an interest rate of LIBOR plus 9.75%, subject to a 2% LIBOR floor. It also allows us to insert a senior facility of up to $100 million, and allows us to implement a discretionary share repurchase plan. In addition, we closed on the previously announced North Fork acquisition, adding the North Fork Unit, including six producing gas wells, which have averaged 1,280 BOEPD since the date of acquisition.

Third Quarter Results

As noted above, total revenues were $16.6 million in the third quarter of fiscal 2014 compared to $8.0 million in the third quarter of the prior fiscal year, an increase of approximately 108% quarter-over-quarter, primarily due to increased oil revenues. Oil revenues totaled $16.3 million in the third quarter of fiscal 2014 compared to $6.7 million in the third quarter of the prior fiscal year, an increase of approximately 143% due to an increase in net barrels sold. Net barrels sold for the third quarter of fiscal 2014 were 172,856, which represents a 103,777 bbl, or 150%, increase as compared to the same period last year.

The increase in net barrels sold resulted from an increase in oil production for the period. Oil production increased 143,660 bbls, or 190%, to 219,422 bbls. The increase was driven by a 140,741 bbl increase in the Cook Inlet region and a 2,919 bbl increase in the Appalachian region. The production increase in the Cook Inlet region resulted from RU-1A, RU-2A, RU-5B, and RU-7 in our Redoubt Shoals field and our new Sword #1 well being on line during the three months ended January 31, 2014. The production increase in the Appalachian region was a result of new production from our CPP H-1 and Brimstone H-1 wells.

The difference between net barrels sold and net barrels produced is approximately equal to the change in quantity of our crude oil inventory balance during the period. Although we attempt to minimize crude oil inventory balances, shipping schedules in the Cook Inlet region are beyond our control and occasionally require us to store crude oil. In addition, we are required to maintain certain inventory levels in third party pipelines and storage facilities. As noted in the following table, we experienced an above average increase in inventory levels during the third quarter of fiscal 2014, which significantly reduced the potential revenue that may have resulted from our increased oil production during the current period. The increase in our inventory balance primarily resulted from shipping schedules and a requirement to maintain increased inventory levels in third party facilities in the Cook Inlet region.

			For the Three Months Ended January 31, 2014
			Cook Inlet			Appalachian			Total
In barrels:
	Beginning inventory balance		29,433			17,357			46,790
	Gross production		254,211			14,330			268,541
	Gross sales		(197,717	)		(13,734	)		(211,451	)
	Pipeline adjustments		153			--			153
	Ending inventory balance		86,080			17,953			104,033
Net change in inventory			56,647			596			57,243

Total operating expenses rose to $23.2 million in the third quarter of fiscal 2014 from $14.5 million in the third quarter of fiscal 2013. Oil and gas operating costs increased to $5.8 million in the third quarter of fiscal 2014 compared with $4.1 million in the third quarter fiscal 2013, primarily as a result of increased production. General and administrative expenses were $7.6 million in the third quarter of fiscal 2014 compared with $5.5 million in the third quarter of fiscal 2013, primarily due to increases in salaries and professional fees. Depreciation, depletion and amortization expense rose to $7.6 million in the third quarter of fiscal 2014 compared with $3.3 million in the third quarter of fiscal 2013, primarily as a result of increased production.

Operating loss for the third quarter of fiscal 2014 was $6.6 million compared with an operating loss of $6.5 million in the third quarter of fiscal 2013.

Other income was $1.3 million in the third quarter of fiscal 2014 compared with other expense of $2.8 million in the third quarter of fiscal 2013. The results for the third quarter of fiscal 2014 included a $1.7 million gain on derivatives compared with a $1.7 million loss on derivatives in the third quarter of fiscal 2013. We experience volatility in unrealized gains and losses on derivatives as a result of not using hedge accounting.

Loss before income taxes decreased to $5.3 million for the third quarter of fiscal 2014, compared to a loss before income taxes of $9.3 million for the third quarter of fiscal 2013.

Adjusted EBITDA rose to $4.3 million for the third quarter of fiscal 2014 as compared to an adjusted EBITDA loss of $0.8 million in the third quarter of fiscal 2013.

The Company recorded a net loss attributable to common stockholders of $6.8 million, or $0.15 per diluted share, for the third quarter of fiscal 2014, compared to a net loss attributable to common stockholders of $6.2 million, or $0.14 per diluted share, for the same period in fiscal 2013.

Nine Months Results

Total revenue for the nine months ended January 31, 2014 rose to $48.4 million compared with $27.1 million for the nine months ended January 31, 2013, an increase of approximately 79% year-over-year, primarily due to increased oil revenues. Oil revenues totaled $47.0 million for the nine months ended January 31, 2014 compared to $22.3 million for the nine months ended January 31, 2013, an increase of approximately 111% due to an increase in net barrels sold. Net barrels sold for the nine months ended January 31, 2014 were 469,387, which represents a 260,866 bbl, or 125%, increase as compared to the same period last year.

The increase in net barrels sold resulted from an increase in oil production for the period. Oil production increased 297,444 bbls, or 136%, to 516,138 bbls. The increase was driven by a 290,059 bbls increase in the Cook Inlet region and a 7,385 bbls increase in the Appalachian region. The production increase in the Cook Inlet region resulted from RU-1A, RU-2A, RU-5B, and RU-7 in our Redoubt Shoals field and our new Sword #1 well being on line during the nine months ended January 31, 2014. The production increase in the Appalachian region was a result of new production from our CPP H-1 and Brimstone H-1 wells.

The difference between net barrels sold and net barrels produced is approximately equal to the change in quantity of our crude oil inventory balance during the period. Although we attempt to minimize crude oil inventory balances, shipping schedules in the Cook Inlet region are beyond our control and occasionally require us to store crude oil. In addition, we are required to maintain certain inventory levels in third party pipelines and storage facilities. As noted in the following table, we experienced an above average increase in inventory levels during the first nine months of fiscal 2014, which significantly reduced the potential revenue that may have resulted from our increased oil production during the current period. The increase in our inventory balance primarily resulted from shipping schedules and a requirement to maintain increased inventory levels in third party facilities in the Cook Inlet region.

			For the Nine Months Ended January 31, 2014
			Cook Inlet			Appalachian			Total
In barrels:
	Beginning inventory balance		30,130			24,063			54,193
	Gross production		595,082			37,953			633,035
	Gross sales		(537,782	)		(44,063	)		(581,845	)
	Pipeline adjustments		(1,350	)		--			(1,350	)
	Ending inventory balance		86,080			17,953			104,033
Net change in inventory			55,950			(6,110	)		49,840

Total operating expenses rose to $65.5 million for the nine months ended January 31, 2014 from $44.7 million in the first nine months of fiscal 2013. Oil and gas operating costs increased to $18.2 million for the nine months ended January 31, 2014, compared with $13.0 million for the nine months ended January 31, 2013, primarily due to increased production. General and administrative expenses increased 24% to $21.1 million for the nine months ended January 31, 2014 compared with $17.1 million for the nine months ended January 31, 2013 due to increases in salaries and professional fees. Depreciation, depletion, and amortization expense increased to $22.4 million for the nine months ended January 31, 2014 compared with $9.5 million for the nine months ended January 31, 2013, primarily as a result of increased production.

Operating loss for the nine months ended January 31, 2014 was $17.0 million compared with an operating loss of $17.6 million for the nine months ended January 31, 2013.

Other expense was $9.6 million for the nine months ended January 31, 2014 compared with $2.1 million in other income for the nine months ended January 31, 2013. The results for the nine months ended January 31, 2014 included a $5.6 million loss on derivatives compared with a $5.2 million gain on derivatives for the nine months ended January 31, 2013. We experience volatility in unrealized gains and losses on derivatives as a result of not using hedge accounting.

Loss before income taxes increased to $26.7 million for the nine months ended January 31, 2014, compared to a loss before income taxes of $15.5 million for the nine months ended January 31, 2013.

Adjusted EBITDA rose to $11.4 million for the nine months ended January 31, 2014 as compared to adjusted EBITDA of $2.3 million for the nine months ended January 31, 2013.

The Company recorded a net loss attributable to common stockholders of $24.5 million, or $0.56 per diluted share, for the nine months ended January 31, 2014, compared to a net loss attributable to common stockholders of $12.4 million, or $0.29 per diluted share, for the same period in fiscal 2013.

Outlook

As we progress into the final quarter of fiscal 2014, we believe our inventory of recompletions, workovers, exploration and development projects and newly acquired assets offer numerous growth opportunities. We are in the process of bringing our WMRU-8 onshore oil well online, and have spudded our RU-9 offshore oil well. We have begun moving the Patterson 191 rig to drill our WMRU-2B well, which will utilize the non-producing existing WMRU-2A wellbore to reduce capital costs. We also plan to perforate additional zones in the Sword #1 well. By adding production from the North Fork Unit, RU-9, WMRU-8 and the Sword #1 well, the Company expects to reach 6,000 BOEPD before the end of fiscal 2014.

From a financial perspective, the company is working to secure lower cost first lien financing prior to the end of our fiscal year. In addition, we look forward to continuing our work with Tesoro on the Trans-Foreland Pipeline, which will give us a direct and continuous connection to the Tesoro refinery.

Investor Conference Call

Mr. Scott Boruff, CEO of Miller Energy, Mr. David Voyticky, President, Mr. John Brawley, CFO, and Mr. David Hall, COO, will host Miller's fiscal 2014 third quarter earnings call. To attend the call, please use the dial in information below. When prompted, ask for the "Miller Energy Resources Q3 2014 conference call."

Date:		March 13, 2014
Time:		4:30 pm Eastern Time US
Dial-In (U.S.):		+1-877-941-1427
International Dial-In:		+1-480-629-9664
Conference ID:		4674019
Webcast:		http://public.viavid.com/index.php?id=108273

Please dial in at least 10-minutes before the call to ensure timely participation.

A playback of the call will be available from 7:30 p.m. ET on March 13, 2014 to 11:59 p.m. ET on March 15, 2014. To listen, call 1-877-870-5176 within the United States or 1-858-384-5517 when calling internationally. Please use the replay pin number 4674019.

About Miller Energy Resources

Miller Energy Resources is an oil and natural gas exploration, production and drilling company operating in multiple exploration and production basins in North America. Miller's focus is in Cook Inlet, Alaska and in the heart of Tennessee's prolific and hydrocarbon-rich Appalachian Basin including the Mississippian Lime and Chattanooga Shale. Miller is headquartered in Knoxville, Tennessee with offices in Anchorage, Alaska and Huntsville, Tennessee. The Company's common stock is listed on the NYSE under the symbol MILL.

Statements Regarding Forward-Looking Information

Certain statements in this press release and elsewhere by Miller Energy Resources, Inc. are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements involve the implied assessment that the resources described can be profitably produced in the future, based on certain estimates and assumptions. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks, uncertainties and other factors that could cause actual results to differ materially from those anticipated by Miller Energy Resources, Inc. and described in the forward-looking statements. These risks, uncertainties and other factors include, but are not limited to, the potential for Miller to experience additional operating losses; material weaknesses in Miller's internal control over financial reporting and the need to enhance Miller's management, systems, accounting, controls and reporting performance; high debt costs under Miller's existing senior credit facility; potential limitations imposed by debt covenants under the senior credit facility on Miller's growth and ability to meet our business objectives; Miller's ability to meet the financial and production covenants contained in the Apollo Credit Facility; whether Miller are able to complete or commence drilling projects within the expected time frame; litigation risks; the ability to perform under the terms of oil and gas leases, and exploration licenses with the Alaska DNR, including meeting the funding or work commitments of those agreements; uncertainties related to deficiencies identified by the SEC in our Form 10-K for 2011; Miller's ability to successfully acquire, integrate and exploit new productive assets in the future; whether Miller can establish production on certain leases in a timely manner before expiration; the ability to complete the work commitments required as terms of the Susitna Basin Exploration Licenses; the ability to recover proved undeveloped reserves and convert probable and possible reserves to proved reserves; Miller's experience with horizontal drilling; risks associated with the hedging of commodity prices; the dependence on third party transportation facilities; concentration risk in the market for the oil we produce in Alaska; the impact of natural disasters on our Cook Inlet Basin operations; the effect of global market conditions on the ability to obtain reasonable financing and on the prices of Miller's common, Series C and Series D Preferred Stock; the imprecise nature of our reserve estimates; risks related to drilling dry holes or wells without commercial quantities of hydrocarbons; fluctuating oil and gas prices and the impact on Miller's results from operations; the need to discover or acquire new reserves in the future to avoid declines in production; differences between the present value of cash flows from proved reserves and the market value of those reserves; the existence within the industry of risks that may be uninsurable; strong industry competition; constraints on production and costs of compliance that may arise from current and future environmental, FERC and other statutes, rules and regulations at the state and federal level; new regulation on derivative instruments used to manage risk against fluctuating commodity prices; the impact that future legislation could have on access to tax incentives currently enjoyed by Miller; that no dividends may be paid on our common stock for some time; cashless exercise provisions of outstanding warrants; market overhang related to restricted securities and outstanding options, and warrants; the impact of non-cash gains and losses from derivative accounting on future financial results; risks to non-affiliate shareholders arising from the substantial ownership positions of affiliates; the junior ranking of the Series C and Series D Preferred Stock to the Series B Preferred Stock and all indebtedness; the ability to pay dividends on the Series C or Series D Preferred Stock; whether the Series C or Series D Preferred Stock is rated; the ability of the Series C or Series D Preferred Stockholders to exercise conversion rights upon a Change of Control; fluctuations in the market price of the Series C and Series D Preferred Stock; whether additional shares of Series C or Series D Preferred Stock or additional series of preferred stock that rank on parity with the Series C or Series D Preferred Stock are issued; the very limited voting rights held by Series C and Series D Preferred Stockholders; the newness of the Series C and Series D Preferred Stock and their limited trading markets; risks related to the continued listing of the Series C or Series D Preferred Stock on the NYSE; and the effect of the change of control conversion feature of the Series C or Series D Preferred Stock on a potential change in control. Additional information on these and other factors, which could affect Miller's operations or financial results, are included in Miller Energy Resources, Inc.'s reports on file with United States Securities and Exchange Commission including its Annual Report on Form 10-K, as amended, for the fiscal year ended April 30, 2013. Miller Energy Resources, Inc.'s actual results could differ materially from those anticipated in these forward- looking statements as a result of a variety of factors, including those discussed in its periodic reports that are filed with the Securities and Exchange Commission and available on its Web site (www.sec.gov). All forward-looking statements attributable to Miller Energy Resources or to persons acting on its behalf are expressly qualified in their entirety by these factors. Investors should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. We assume no obligation to update forward-looking statements should circumstances or management's estimates or opinions change unless otherwise required under securities law.

MILLER ENERGY RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(Dollars in thousands, except per share data)
			January 31,  2014				April 30,  2013
ASSETS
CURRENT ASSETS:
	Cash and cash equivalents		$	13,184			$	2,551
	Restricted cash			4,066				7,531
	Accounts receivable			1,137				3,204
	Alaska production tax credits receivable			19,763				12,713
	Inventory			4,944				3,382
	Prepaid expenses and other			8,371				1,183
Total current assets				51,465				30,564
OIL AND GAS PROPERTIES, NET				568,808				491,314
EQUIPMENT, NET				34,860				37,571
OTHER ASSETS:
	Land			542				542
	Restricted cash, non-current			12,007				10,207
	Deferred financing costs, net			1,607				2,085
	Other assets			1,809				541
Total assets			$	671,098			$	572,824
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
	Accounts payable		$	40,538			$	13,129
	Accrued expenses			18,527				6,338
	Short-term portion of derivative instruments			1,758				842
	Current portion of long-term debt			--				6,000
Total current liabilities				60,823				26,309
OTHER LIABILITIES:
	Deferred income taxes			145,890				157,530
	Asset retirement obligation			20,967				19,890
	Long-term portion of derivative instruments			3,152				--
	Long-term debt, less current portion			74,268				48,978
Total liabilities				305,100				252,707
MEZZANINE EQUITY:
	Series C Cumulative Preferred Stock, redemption amount of $78,124, 3,250,000 shares authorized, 3,069,968 and 1,454,901 shares issued and outstanding as of January 31, 2014 and April 30, 2013, respectively			67,097				31,236
STOCKHOLDERS' EQUITY:
	Series D Cumulative Redeemable Preferred Stock, redemption amount of $32,342, 4,000,000 shares authorized, 1,069,031 and 0 shares issued and outstanding as of January 31, 2014 and April 30, 2013, respectively			29,885				--
	Series D Cumulative Redeemable Preferred Stock, held in escrow			(5,000	)			--
	Common stock, $0.0001 par, 500,000,000 shares authorized, 45,231,447 and 43,444,694 shares issued and outstanding as of January 31, 2014 and April 30, 2013, respectively			4				4
	Additional paid-in capital			97,845				88,184
	Retained earnings			176,167				200,693
Total stockholders' equity				298,901				288,881
Total liabilities and stockholders' equity			$	671,098			$	572,824

MILLER ENERGY RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(Dollars in thousands, except share and per share data)
			Three Months Ended January 31,								Nine Months Ended January 31,
			2014				2013				2014				2013
REVENUES:
	Oil sales		$	16,348			$	6,720			$	47,012			$	22,310
	Natural gas sales			118				133				671				328
	Other			162				1,146				749				4,433
Total revenues				16,628				7,999				48,432				27,071
OPERATING EXPENSES:
	Oil and gas operating			5,821				4,118				18,249				12,963
	Cost of other revenue			256				1,051				844				4,084
	General and administrative			7,587				5,518				21,092				17,056
	Exploration expense			352				187				786				244
	Depreciation, depletion and amortization			7,642				3,341				22,352				9,528
	Accretion of asset retirement obligation			305				284				903				853
	Other operating expense (income), net			1,250				--				1,250				(65	)
Total operating expenses				23,213				14,499				65,476				44,663
OPERATING LOSS				(6,585	)			(6,500	)			(17,044	)			(17,592	)
OTHER INCOME (EXPENSE):
	Interest expense, net			(407	)			(1,117	)			(4,051	)			(2,785	)
	Gain (loss) on derivatives, net			1,677				(1,681	)			(5,589	)			5,215
	Other income (expense), net			42				25				26				(350	)
Total other income (expense)				1,312				(2,773	)			(9,614	)			2,080
LOSS BEFORE INCOME TAXES				(5,273	)			(9,273	)			(26,658	)			(15,512	)
	Income tax benefit			2,171				3,931				11,640				6,551
NET LOSS				(3,102	)			(5,342	)			(15,018	)			(8,961	)
	Accretion of Series A, C and D preferred stock			(817	)			(145	)			(1,935	)			(2,605	)
	Series C and D preferred stock cumulative dividends			(2,905	)			(677	)			(7,573	)			(809	)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS			$	(6,824	)		$	(6,164	)		$	(24,526	)		$	(12,375	)
LOSS PER COMMON SHARE:
	Basic		$	(0.15	)		$	(0.14	)		$	(0.56	)		$	(0.29	)
	Diluted		$	(0.15	)		$	(0.14	)		$	(0.56	)		$	(0.29	)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
	Basic			44,886,838				43,367,781				44,141,222				42,445,223
	Diluted			44,886,838				43,367,781				44,141,222				42,445,223

MILLER ENERGY RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(Dollars in thousands)
				Nine Months Ended January 31,
				2014				2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss				$	(15,018	)		$	(8,961	)
Adjustments to reconcile net loss to net cash provided by operating activities:
	Depreciation, depletion and amortization				22,352				9,528
	Amortization of deferred financing fees and debt discount				1,113				549
	Expense from issuance of equity				5,120				7,630
	Dry hole costs, leasehold impairments and non-cash exploration expenses				157				--
	Deferred income taxes				(11,640	)			(6,551	)
	Derivative contracts:
		(Gain) loss on derivatives, net			5,589				(5,215	)
		Cash settlements			(2,765	)			2,276
	Accretion of asset retirement obligation				903				853
	Other				1,949				--
Changes in operating assets and liabilities:
	Receivables				5,084				996
	Inventory				372				(467	)
	Prepaid expenses and other assets				(1,788	)			(1,445	)
	Accounts payable, accrued expenses and other				3,849				6,944
NET CASH PROVIDED BY OPERATING ACTIVITIES					15,277				6,137
CASH FLOWS FROM INVESTING ACTIVITIES:
	Capital expenditures for oil and gas properties				(94,388	)			(23,213	)
	Proceeds from Alaska production tax credits				18,561				--
	North Fork purchase deposit				(3,000	)			--
	Prepayment of drilling costs				(2,302	)			--
	Purchase of equipment and improvements				(986	)			(9,606	)
	Proceeds from sale of equipment				--				2,000
NET CASH USED IN INVESTING ACTIVITIES					(82,115	)			(30,819	)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Cash dividends				(5,646	)			(285	)
	Payments on debt				--				(24,130	)
	Proceeds from borrowings				20,000				40,000
	Debt acquisition costs				(1,900	)			(3,854	)
	Redemption of preferred stock				--				(11,240	)
	Issuance of preferred stock				62,704				20,448
	Equity issuance costs				(3,893	)			(1,576	)
	Exercise of equity rights				4,538				3,832
	Restricted cash				1,665				(992	)
	Other				3				--
NET CASH PROVIDED BY FINANCING ACTIVITIES					77,471				22,203
NET CHANGE IN CASH AND CASH EQUIVALENTS					10,633				(2,479	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD					2,551				3,971
CASH AND CASH EQUIVALENTS AT END OF PERIOD				$	13,184			$	1,492
SUPPLEMENTARY CASH FLOW DATA:
	Cash paid for interest			$	5,805			$	8,895
SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
	Capital expenditures in accounts payable and accrued expenses			$	32,572			$	6,702
	Reduction of oil and gas properties and equipment from applications for Alaska production tax credits			$	28,906			$	--
	Issuance of Series D Preferred Stock held in escrow			$	5,000			$	--
	Accretion of preferred stock			$	1,935			$	2,605

Regulation G Disclosure - Discussion of Non-GAAP Financial Data and Reconciliation to GAAP
This press release contains non-GAAP financial measures within the meaning of Regulation G and Item 10(e) of Regulation S-K, as promulgated by the SEC. The presentation of this financial information is not intended to be considered in isolation or as a substitute for, or superior to, the financial information prepared and presented in accordance with GAAP, including that in our public filings.

To supplement the Company's condensed consolidated financial statements, which statements are prepared and presented in accordance with GAAP, we use non-GAAP adjusted EBITDA, or adjusted Earnings Before Income Taxes, Depreciation and Amortization, as a measure to evaluate earnings by excluding certain non-cash expenses as set forth in the table below. The Company uses this non-GAAP financial measure for financial and operational decision making and as a means to evaluate period-to-period comparisons. Management believes that this non-GAAP financial measure provides meaningful supplemental information regarding the Company's performance and liquidity. The Company believes that both management and investors benefit from referring to this non-GAAP financial measure in assessing performance and when planning, forecasting and analyzing future periods. This non-GAAP financial measure also facilitates management's internal comparisons to historical performance and liquidity as well as comparisons to competitors' operating results. The Company believes this non-GAAP financial measure is useful to investors both because (1) it allows for greater transparency with respect to key metrics used by management in its financial and operational decision making and (2) it is used by our institutional investors and the analyst community to help them analyze the health of the business.

Adjusted EBITDA Reconciliations

				For the Three Months Ended January 31,								For the Nine Months Ended January 31,
				2014				2013				2014				2013
				(dollars in thousands)
Loss before income taxes				$	(5,273	)		$	(9,273	)		$	(26,658	)		$	(15,512	)
Adjusted by:
	Interest expense, net				407				1,117				4,051				2,785
	Depreciation, depletion and amortization				7,642				3,341				22,352				9,528
	Accretion of asset retirement obligation				305				284				903				853
	Exploration costs				352				187				786				244
	Stock-based compensation				1,546				2,652				5,120				7,367
	Non-recurring litigation settlements and matters				1,998				--				1,998				--
	Derivative contracts:
		(Gain) loss on derivatives, net			(1,677	)			1,681				5,589				(5,215	)
		Cash settlements			(983	)			(822	)			(2,765	)			2,276
Adjusted EBITDA				$	4,317			$	(833	)		$	11,376			$	2,326