Alexander Energy Ltd. Announces a 47% Increase in Q1 Cash Flow to $1.8 Million

CALGARY, ALBERTA--(Marketwired - May 28, 2013) - Alexander Energy Ltd. (TSX VENTURE:ALX) ("Alexander" or the "Company") has filed its Interim Financial Statements and related Management's Discussion and Analysis for the three months ended March 31, 2013 all of which are available on the Company's profile at www.SEDAR.com ("SEDAR").

The Company is pleased to announce its highest quarterly cash flow since Q3 2008. Alexander achieved cash flow of $1.8 million in Q1 2013, up 47% from 2012, despite a 9% decrease in oil prices and an increase in per barrel royalty expense. Importantly, net debt decreased slightly while net debt to annualized cash flow fell sharply from 2.5:1 to 1.7:1.

This was achieved without any production from the $1.5 million first quarter drilling program which resulted in two successful wells. The 7-7-56-26W4 well was put on production in April at 60 bbls/day (48 bbls/day net) and the 12-12-56-27W4 well is expected to be put on production in mid-June at 125 bbls/day (118 bbls/day net).

In Q2 2013 the Company carried out a recompletion/workover on an upper Detrital zone in the 11-12-56-27W4 well that tested at over 260 bbls/day (244 bbls/day net).

Including the 11-12-56-27W4 recompletion/workover, the Company expects over 200 bbls/day (net) of new production to be on-stream by mid-June. We are currently working on preliminary estimates of reserve additions from our recent successes.

This is reflective of the success of the program put into place by the new management team starting from the AGM in September, 2012. Management's strategy can be summarized as investing in our Alexander property and improving our operations prior to looking to sell or merge the Company when the right opportunity is presented, hopefully by the end of 2013.

Starting from the September 7^th, 2012 AGM your Company has directed all spending to Company enhancing activities. We have invested in drilling, workovers, seismic interpretation, geological and geophysical interpretation, critical land activities, and perhaps most importantly on an engineering analysis of a potential waterflood on our property with an associated application to the ERCB for an extension to our maximum allowable production rates which was approved by the ERCB.

In the six months prior to the AGM in September 2012, your Company spent $85,000 per month on legal, proxy, financial advisor and director fees. In the first quarter of 2013 the comparable monthly expense was $1,800, a saving of $83,200 (98%) per month.

Your management team has made significant progress in rebuilding the land files, updating critical leases affecting our oil production, rebuilding the well files, continuing with our required engineering work, analyzing our 3D seismic and drilling successful wells. The result of all of this is a much better understanding of our key property. This is critical for our relationship with the ERCB regarding the possibility of being granted GPP (good production practices) status or waterflood approval, or an additional extension of our allowable maximum production rates.

We now believe that the Detrital zone may continue to the south east of our existing producing wells. We have acquired 2 1/2 sections of land and associated 3D seismic which we are currently processing using our proprietary analysis. We also own other land in the general area which may be prospective for Detrital production.

Alexander will continue to focus on maximizing the Company's value, reducing the debt, and preparing for a process to maximize shareholder value, possibly this fall.

Recently Alexander has received communication from some significant shareholders who have indicated they would like to take control of the Company. After the numerous expensive distractions and disruptions the Company has experienced over the past few years we have now built positive momentum and a positive environment. We do not believe that yet another management team is in the best interests of shareholders.

Specific accomplishments for Alexander in 2013 include:

• Increased cash flow to $1.8 million in Q1 2013 ($0.03/share), up 47% over Q1 2012.
• Reduced funds spent on legal, proxy, financial advisor and director fees to $1,800 per month, down 98% from the $85,000 per month spent prior to the September 2012 AGM.
• Oil production increased to 452 bbls/day, up 37% over Q1 2012.
• Increased average production volumes to 900 barrels of oil equivalent per day representing a 17% increase over the 769 boe per day of production in the first quarter of 2012.
• Executed a drilling program with 100% success, investing $1.5 million, drilling 2 gross (1.73 net) oil wells. The 7-7 well is on stream and producing at 60 bbls/day (48 bbls/day net), and the 12-12 well tested at 240 bbls/day (226 bbls/day net) and is currently being tied in.
• Received approval from the ERCB to extend maximum production allowable per well of 125 bbls/day until spring, 2014.
• Carried out a recompletion/workover on the 11-12 well that tested at over 260 bbls/day (244 bbls/day net).
• Improved the Company's operating netback to $26.04 per boe representing an 8% increase over the same period in 2012.
• Acquired 2.5 sections of land east of our current acreage complete with 3D seismic (East Detrital). Preliminary evaluations indicate the potential of additional Detrital sands.
• Reduced net debt to annualized cash flow ratio to 1.7:1.
• Expecting over 200 bbls/day (net) of production additions in Q2 2013.

To receive Press Releases and Corporate Updates directly via email send your email address to info@alexanderenergy.ca.

Highlights

Financial summary

Three months ended March 31,		2013	2012	% Change
Oil and natural gas revenue		$ 3,647	$ 2,856	28
Cash flow from operations 1		1,802	1,228	47
	Per share - basic and diluted	0.03	0.02	32
Comprehensive income (loss)		22	(111)	(120)
	Per share - basic and diluted	0.00	(0.00)	-
Total assets		33,161	32,321	2
Net debt 1		12,297	12,451	(1)
Capital expenditures		$ 1,497	$ 846	77
Shares outstanding - end of period		62,239,477	62,239,477	-

thousands of CDN$ - except per share amounts
¹ Non-IFRS measure

Production and commodity prices

Three months ended March 31,	2013	2012	% Change
Daily production
Oil and NGLs (bbl/d)	452	330	37
Natural gas (mcf/d)	2,685	2,631	2
Oil equivalent (boe/d @ 6:1)	900	769	17
Realized commodity prices ($CDN)
Oil and NGLs (bbl/d)	$ 70.54	$ 77.25	(9)
Natural gas (mcf/d)	3.22	2.37	36
Oil equivalent (boe/d @ 6:1)	$ 45.05	$ 41.27	9

Oil and natural gas revenue by product

Three months ended March 31,	2013	2012	% Change
Oil and NGLs (bbl/d)	$ 2,870	$ 2,295	25
Natural gas (mcf/d)	777	561	39
Total revenue	$ 3,647	$ 2,856	28
% Oil and NGLs	79%	80%
% Natural gas	21%	20%

thousands - CDN$

Netbacks

Three months ended March 31,	2013 ($/boe)	2012 ($/boe)	% Change
Operating netback ($ / boe)
Revenue	45.05	41.27	9
Royalties	6.40	3.99	60
Operating expenses	12.61	13.18	(4)
Operating netback per boe	26.04	24.10	8
Realized gain (loss) on financial derivative instruments	1.63	(1.42)	215
General and administrative expenses	3.68	3.01	22
Interest expense	1.73	1.94	(11)
Cash flow from operations per boe	22.26	17.74	25

Liquidity and Financial Condition

As at March 31, 2013, bank debt including working capital (net debt) was $12.3 million. The Company's net debt to first quarter 2013 annualized cash flow from operations was 1.7:1 (March 31, 2012 - 2.5:1).

Alexander has flexibility to finance future expansions of its capital programs, through the use of its current funds generated from operations and its debt facilities. The Company expects to continue to improve the net debt to cash flow ratio in 2013.

Effective March 20, 2013 the Company renewed its credit facilities with a Canadian Chartered Bank. Facility A is a revolving operating demand loan with a maximum limit of $13.0 million. Facility B is a non-revolving acquisition/development demand loan that provides an additional $2.25 million of financing subject to bank approval. Interest is at prime plus 2.0% per annum for Facility A and prime plus 2.5% per annum for Facility B. The Company has the ability to draw on the development loan for acquisitions and the drilling of new wells subject to certain working capital ratio restrictions.

For the balance of 2013, Alexander plans to invest approximately $5.0 million on its capital program within its core area. Alexander intends on financing this capital program from cash flow from operations.

Financial Derivative Instruments

The Company had the following financial derivative instrument contracts in place at March 31, 2013:

Description	Total Quantity	Price	Remaining Term
Oil WTI (CDN$) - Swap	150 bbls/day	$ 104.94/bbl	April 1 - December 31, 2013
Oil WTI (CDN$) - Sold Call	100 bbls/day	$ 100.08/bbl	April 1 - October 31, 2013
Gas AECO (CDN$) - Bought Put	1,000 gj/day	$ 3.00/gj	April 1 - October 31, 2013

The following tables summarize the realized and unrealized gains and losses on financial derivative instruments for the period ended March 31, 2013:

Three months ended March 31,	2013	2012
Realized gain (loss) on financial derivative instruments	$ 132	$ (98)
Unrealized loss on financial derivative instruments	(381)	(71)
Loss on financial derivative instruments	$ (249)	$ (169)

thousands - CDN$

On April 12, 2013 the Company entered into a financial derivative instrument contract.

Description	Total Quantity	Price	Remaining Term
Gas AECO - Swap	700 gj/day	$ 3.58/gj	January 1 - December 31, 2014

Earnings and Cash Flow Summary

Three months ended March 31,	2013	2012	% Change	2013 ($/boe)	2012 ($/boe)	% Change
Oil and natural gas revenue	3,647	2,856	28	45.05	41.27	9
Royalties	518	276	88	6.40	3.99	60
Revenue after royalties	3,129	2,580	21	38.65	37.28	4
Production and operating expenses	1,021	912	12	12.61	13.18	(4)
Operating netback 1	2,108	1,688	26	26.04	24.10	8
Realized gain (loss) on financial derivative instruments	132	(98)	235	1.63	(1.42)	215
General & administrative expenses	298	208	43	3.68	3.01	22
Interest and other financing charges	140	134	4	1.73	1.94	(11)
Cash flow from operations 1	1,802	1,228	47	22.26	17.74	25
Unrealized gain (loss) on financial derivative instruments	(381)	(71)	437	(4.71)	(1.03)	359
Other income	-	230	(100)	0.00	3.32	(100)
Share based compensation	-	87	(100)	0.00	1.26	(100)
Accretion	11	11	-	0.14	0.16	(15)
Depletion and depreciation	1,388	1,400	(1)	17.15	20.23	(15)
Comprehensive income (loss)	22	(111)	(120)	0.27	(1.60)	(117)
Per Share - Basic	0.00	(0.00)
Per Share - Diluted	0.00	(0.00)

thousands of CDN$ - except per share amounts
¹ Non-IFRS measure

Forward-Looking Statements: All statements, other than statements of historical fact, set forth in this news release, including without limitation, assumptions and statements regarding the volumes and estimated value of the Company's proved and probable reserves, future production rates, exploration and development results, financial results, and future plans, operations and objectives of the Company are forward-looking statements that involve substantial known and unknown risks and uncertainties. Some of these risks and uncertainties are beyond management's control, including but not limited to, the impact of general economic conditions, industry conditions, fluctuation of commodity prices, fluctuation of foreign exchange rates, environmental risks, industry competition, availability of qualified personnel and management, availability of materials, equipment and third party services, stock market volatility, timely and cost effective access to sufficient capital from internal and external sources. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable by the Company at the time of preparation, may prove to be incorrect. There can be no assurance that such statements will prove to be accurate and actual results and future events could differ materially from those anticipated in such statements.

These assumptions and statements necessarily involve known and unknown risks and uncertainties inherent in the oil and gas industry such as geological, technical, drilling and processing problems and other risks and uncertainties, as well as the business risks discussed in Management's Discussion and Analysis of the Company under the heading "Business Risks". The Company does not undertake any obligation, except as required by applicable securities legislation, to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise.

Barrels of oil equivalent (boe) is calculated using the conversion factor of 6 mcf (thousand cubic feet) of natural gas being equivalent to one barrel of oil. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl (barrel) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.