PostRock Energy (PSTR) 8-K PostRock Reports Second Quarter Results

PostRock Reports Second Quarter Results

OKLAHOMA CITY – August 6, 2014 – PostRock Energy Corporation (NASDAQ: PSTR) today announced results for the quarter ended June 30, 2014.

Highlights

· Revenue rose to $21.6 million, up 10% from the prior-year period.

· Production, at the quarter’s 23:1 oil-to-gas economic equivalency, averaged 52.3 MMcfe per day, flat with the prior-year period.

· Oil production averaged 682 barrels per day, up 25% from the prior-year period and just shy of 30% of total production on an economic equivalency basis.

· During the quarter, oil development activities in Central Oklahoma accelerated. A very successful workover program initiated earlier in the year continued with seven operations completed in the quarter, and two horizontal wells targeting the Hunton formation were drilled. The first well was placed on production in late June. Its production recently peaked after 43 days on line at over 600 barrels per day. The second well has been on production for 18 days. Although not performing as well as the first, it recently exceeded 100 barrels per day, and is expected to increase as stimulation load is recovered.  Combined, the two wells’ results continue to significantly outperform the original forecast.

· As a result of the quarter’s development, Company oil production is currently over 900 barrels per day, and total production, at 23:1 economic equivalency, is 58.6 MMcfe per day.

· In June, a joint venture covering 28 square miles in Central Oklahoma was entered into with Silver Creek Oil & Gas, LLC (“Silver Creek”) to test the Woodford Shale.

Operations

Central Oklahoma – Oil production averaged 449 net barrels per day in the quarter, a 143% increase over the prior-year period. Since March, twelve workovers have targeted the Hunton formation, including seven in the second quarter, at a cost of approximately $3 million. These projects have projected IRR of over 100%. Two horizontal wells, also targeting the Hunton, were drilled during the quarter. As noted above, the first recently peaked at over 600 barrels per day and has produced 14,000 barrels since coming on production in late June. The second well was put on production in July and recently surpassed 100 barrels per day.  It will likely be another 2-3 weeks before full stimulation load is recovered and the well reaches peak. As noted, the wells’ combined results are substantially exceeding forecast. The two wells were drilled and completed for a combined $6.2 million.

In June, a joint venture (“JV”) was finalized with Silver Creek covering approximately 17,900 gross acres in Cleveland and Pottawatomie Counties in Central Oklahoma. The JV includes an acre for acre swap between PostRock and Silver Creek of approximately 3,800 net acres over a 28 square mile area. The acreage contributed by PostRock represented approximately 10% of the Company’s Central Oklahoma leasehold. In connection with the JV, PostRock sold approximately 1,150 net acres to Silver Creek for $466,000. The JV will facilitate the initial Woodford horizontal tests in the area with PostRock and Silver Creek having a 30%/70% ownership split, respectively. Silver Creek will serve as the operator. Locations for the first two horizontal wells have been selected and drilling should begin shortly.

In the final six months of the year, the Company expects to spend approximately $14.5 million on its share of four to five horizontal wells targeting the Hunton and the Woodford shale formations, at least one vertical well targeting multiple zones, and three to five additional workovers, all in Central Oklahoma. At current prices, we expect to fund this development out of operating cash flow.

Cherokee Basin – Net production for the quarter averaged 35.1 MMcf and 194 barrels per day, 9% and 39%, respectively, below the prior-year period. The sharp decline was due to the lack of any development spending since August 2013. Gas prices have not remained at high enough levels to justify drilling, and the oil development effort in the area proved disappointing. Without development, Cherokee Basin oil production is expected to decline at 5-7% per year. Gas decline was a slight improvement from the historic decline due to compression fuel savings.

The Cherokee Basin compression reconfiguration was completed in May with inception-to-date costs of $8.3 million. Annual rental savings now approximate $4.6 million. In addition, the project reduced fuel consumption by roughly 1.6 MMcf a day as referenced above. At current prices, fuel savings should add a further $2.1 million to operating income. We expect per unit operating costs to trend down slightly as the full savings from the compression project are realized through the balance of the year.

Financial Performance

Revenues for the quarter increased 10% from the prior-year period to $21.6 million. Despite lower volumes, gas revenue increased slightly to $14.7 million, due to an 11% increase in realized prices to $4.39 per Mcf. Oil revenue increased 39% to $6.2 million, as production grew 25% and the realized price of $99.82 per barrel was 11% higher than the prior-year period. Gas gathering revenue increased 4% to $746,000, as higher gas prices more than offset lower third-party volumes in the Cherokee Basin.

Total production costs, consisting of lease operating expenses (“LOE”), gathering expenses, and severance and ad valorem taxes (“production taxes”) decreased slightly from the prior-year period to $10.6 million. The decrease was driven by lower Cherokee Basin lease operating costs of $879,000 due to compressor rental savings. This was partially offset by an increase in lease operating costs of $669,000 in Central Oklahoma. These higher costs are primarily related to more than doubling the Central Oklahoma well count and higher total fluid production in Central Oklahoma. Per-unit operating costs are expected to trend downward as volumes increase.

General and administrative expenses decreased 18%, or $760,000, from the prior-year period to $3.5 million. Excluding a $528,000 charge from a worker’s compensation audit expensed in the prior-year period, G&A decreased 6%. The decrease was largely due to a $319,000 decrease in non-cash compensation. Presently, the Company does not expect material changes to G&A for the balance of the year.

As a result of the warrant exchange transaction executed in December 2013, a portion of our redeemable preferred stock became mandatorily redeemable and moved from mezzanine equity to debt on our balance sheet. Consequently, accretion and paid-in-kind dividends, both non-cash items, associated with the mandatorily redeemable preferred stock are recorded as interest expense. As a result, $2.6 million of non-cash interest expense was added during the quarter. Excluding this expense, net interest expense was $915,000, an increase of 16% over the prior-year period, as debt outstanding increased 12%.

The Company had a $1.9 million realized hedging loss in the quarter compared to a $1.3 million loss in the prior-year period, as a result of higher gas and oil prices.

During the quarter, the market price of CEP units rose $0.06 per unit, causing a mark-to-market gain of $87,000.

Hedges

Natural gas and crude oil swaps cover an average of 28.1 MMcf and 315 barrels per day for the final six months of 2014 at weighted average prices of $4.01 per Mcf and $95.19 per barrel. This represents approximately 80% of anticipated gas production, and 35% of anticipated oil production, respectively. The following table summarizes the Company’s hedge position at June 30, 2014.

	July - Dec.
	2014		2015		2016
NYMEX Gas Swaps
Volume (MMBtu)		5,163,786		8,983,560		7,814,028
Weighted Average Price ($/MMBtu)	$	4.01	$	4.01	$	4.01
NYMEX Oil Swaps
Volume (Bbls)		58,038		71,568		65,568
Weighted Average Price ($/Bbl)	$	95.19	$	92.73	$	90.33

Debt

At June 30, $87.0 million was borrowed under the revolving credit facility, a drop of $8.0 million from March 31. The $8.3 million received in the CEP settlement along with proceeds from subsequent sales of CEP units, was used to reduce debt. At July 31, $84.5 million was drawn on the facility with $1.4 million in letters of credit outstanding, and there was $29.1 million of availability. 

At June 30, PostRock paid in-kind its quarterly dividend on the Series A preferred stock. This increased the liquidation value of the preferred by $3.2 million to $109.1 million. White Deer also received 2.1 million additional warrants with a weighted average strike price of $1.53 a share. At June 30, White Deer held a total of 24.7 million warrants exercisable at an average price of $1.51 a share and 11.0 million common shares. On July 17, 2014, White Deer extended the date through which the Company may pay the preferred dividends in kind to June 30, 2016.

	December 31,		June 30,
	2013		2014
Capitalization	(in thousands)
Long-term debt	$	92,000	$	87,000
Mandatorily redeemable preferred stock		64,523		65,345
Redeemable preferred stock		23,828		28,643
Stockholders’ deficit		(30,034)		(40,154)
Total capitalization	$	150,317	$	140,834

Capital Expenditures

During the quarter, capital expenditures totaled $10.7 million. A total of $7.1 million was spent on development, largely consisting of seven workovers and two horizontal wells in Central Oklahoma. A further $1.8 million was spent to complete the Cherokee Basin compressor reconfiguration; and $1.8 million was spent on geological and geophysical, land and maintenance.

CEP Investment

As previously announced, the CEP lawsuit was settled on March 31. The Company expects to recover the full $21.6 million targeted in the settlement agreement. Since the initial transfer of all of the Company’s CEP Class A units and 414,938 Class B units to SEPI on March 31, the Company has sold an additional 1,221,456 Class B units at an average price of $2.44 during the quarter. As of July 31, the Company had sold 2,338,440 Class B units at an average price of $2.57, leaving 3,165,516 remaining units to be sold over the next six to nine months.

Webcast and Conference Call

PostRock will host a webcast and conference call tomorrow, August 7, 2014, at 10:00 a.m. Central Time. The webcast will be accessible on the ‘Investors’ page at www.pstr.com, where it will also be available for replay. The conference call number for participation is (866) 516-1003.

PostRock Energy Corporation is engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas. Its primary production activity is focused in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma, and Central Oklahoma. The Company owns and operates over 3,000 wells and nearly 2,200 miles of gas gathering lines in the Basin. It also owns and operates minor oil and gas producing properties in the Appalachian Basin.

Forward-Looking Statements

Opinions, forecasts, projections or statements, other than statements of historical fact, are forward-looking statements that involve risks and uncertainties. Forward-looking statements in this announcement are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance such expectations will prove correct. Actual results may differ materially due to a variety of factors, some of which may not be foreseen. These risks and other risks are detailed in the Company’s filings with the Securities and Exchange Commission, including risk factors listed in the Annual Report on Form 10-K and other filings. The Company’s SEC filings may be found at www.pstr.com or www.sec.gov. By making these forward-looking statements, the Company undertakes no obligation to update these statements for revisions or changes.

Company Contact:

Stephen L. DeGiusti

EVP, General Counsel & Secretary

sdegiusti@pstr.com

(405) 702-7420

Production for the Current and Prior-Year Periods

The following table represents total period production for the current and prior-year periods:

	Total Period Production
	Three Months Ended June 30,
	2013		2014
Production
Natural gas (MMcf)
Cherokee Basin		3,505		3,194
Central Oklahoma		1		17
Appalachian Basin		129		126
Total natural gas		3,635		3,337
Crude oil (Bbls)
Cherokee Basin		28,872		17,682
Central Oklahoma		16,774		40,825
Appalachian Basin		3,835		3,543
Total crude oil		49,481		62,050
Total Production - Natural Gas Equivalent (MMcfe)
Economic equivalent, 23:1 oil-to-gas basis (1)
Cherokee Basin		4,169		3,601
Central Oklahoma		387		956
Appalachian Basin		217		207
Total natural gas equivalent		4,773		4,764
Energy equivalent, 6:1 oil-to-gas basis (2)
Cherokee Basin		3,678		3,300
Central Oklahoma		101		262
Appalachian Basin		152		147
Total natural gas equivalent		3,931		3,709
Realized price (excluding hedges)
Crude oil (per Bbl)	$	89.81	$	99.82
Natural gas (per Mcf)	$	3.97	$	4.39

_________

(1) Oil and natural gas are converted at the rate of one barrel equals 23 Mcfe based upon the approximate revenue per unit of production (Mcf or Bbl) realized during the period ($99.82 per barrel of oil and $4.39 per Mcf of gas calculates to a 23:1 economic equivalency).

(2) Oil and natural gas are converted at the rate of one barrel equals six Mcfe based upon the approximate relative energy content of oil to natural gas.

Reconciliation of Non-GAAP Financial Measures

The following table represents a reconciliation of net income (loss) to EBITDA and adjusted EBITDA, as defined, for the periods presented.

	Three Months Ended June 30,
	2013		2014
	(in thousands)
Net income (loss)	$	6,880	$	(5,988)
Adjusted for:
Interest expense, net		769		3,483
Depreciation, depletion and amortization		6,693		7,357
EBITDA	$	14,342	$	4,852
Other income, net		(7)		(5)
Gain from equity investment		(863)		(87)
Unrealized (gain) loss from derivative financial instruments		(10,128)		894
Gain on disposal of assets		(41)		(59)
Non-cash compensation		1,236		937
Acquisition costs		—		13
Adjusted EBITDA	$	4,539	$	6,545

Although EBITDA and adjusted EBITDA are not measures of performance calculated in accordance with generally accepted accounting principles (“GAAP”), management considers them important measures of performance. Neither EBITDA nor adjusted EBITDA are a substitute for the GAAP measures of earnings or cash flow or necessarily a measure of the Company’s ability to fund its cash needs. In addition, it should be noted that companies calculate adjusted EBITDA differently, and therefore adjusted EBITDA as presented herein may not be comparable to adjusted EBITDA reported by other companies. EBITDA and adjusted EBITDA have material limitations as a performance measure because they exclude, among other things, (a) interest expense, which is a necessary element of business to the extent that an entity incurs debt, (b) depreciation, depletion and amortization, which are necessary elements of any business that uses capital assets, (c) impairments of oil and gas properties, which may at times be a material element of an independent oil company’s business, and (d) income taxes, which may become a material element of the Company’s operations in the future. Because of their limitations, neither EBITDA nor adjusted EBITDA should be considered a measure of discretionary cash available to us to invest in the growth of PostRock’s business.

PostRock Energy Corporation

Condensed Consolidated Statements of Operations

 (Unaudited)

	Three Months Ended June 30,
	2013		2014
	(in thousands, except per share data)
Revenues
Natural gas sales	$	14,434	$	14,656
Crude oil sales		4,444		6,194
Gathering		716		746
Total		19,594		21,596
Costs and expenses
Production		10,702		10,564
General and administrative		4,259		3,499
Depreciation, depletion and amortization		6,693		7,357
Gain on disposal of assets		(41)		(59)
Acquisition costs		—		13
Total		21,613		21,374
Operating income (loss)		(2,019)		222
Other income (expense)
Realized loss from derivative financial instruments		(1,330)		(1,925)
Unrealized gain (loss) from derivative financial instruments		10,128		(894)
Gain on investment		863		87
Other income, net		7		5
Interest expense, net		(769)		(3,483)
Total		8,899		(6,210)
Income (loss) before income taxes		6,880		(5,988)
Income taxes		—		—
Net income (loss)		6,880		(5,988)
Preferred stock dividends		(2,823)		(1,021)
Accretion of redeemable preferred stock		(826)		(436)
Net income (loss) attributable to common stockholders	$	3,231	$	(7,445)
Net loss per common share
Basic loss per share	$	0.13	$	(0.23)
Diluted loss per share	$	0.13	$	(0.23)
Weighted average common shares outstanding
Basic		24,395		31,799
Diluted		24,509		31,799

PostRock Energy Corporation

Condensed Consolidated Balance Sheets

	December 31,		June 30,
	2013		2014
			(Unaudited)
	(in thousands)
ASSETS
Current assets
Cash and equivalents	$	37	$	—
Restricted cash		—		56
Accounts receivable—trade, net		7,722		8,138
Other receivables		194		658
Inventory		886		961
Other		820		1,291
Derivative financial instruments		54		—
Total		9,713		11,104
Oil and natural gas properties, full cost method of accounting, net		141,911		146,236
Other property and equipment, net		14,180		13,142
Investment, net		14,588		4,979
Derivative financial instruments		652		—
Other, net		2,038		1,789
Total assets	$	183,082	$	177,250
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities
Accounts payable	$	7,406	$	7,984
Revenue payable		4,397		4,542
Accrued expenses and other		4,055		3,830
Derivative financial instruments		1,937		4,186
Total		17,795		20,542
Derivative financial instruments		1,796		2,343
Long-term debt		92,000		87,000
Mandatorily redeemable preferred stock		64,523		65,345
Asset retirement obligations		13,099		13,531
Other		75		—
Total liabilities		189,288		188,761
Commitments and contingencies
Series A Cumulative Redeemable Preferred Stock		23,828		28,643
Stockholders’ deficit
Preferred stock		1		2
Common stock		299		326
Additional paid-in capital		397,170		401,269
Treasury stock, at cost		(512)		(2,448)
Accumulated deficit		(426,992)		(439,303)
Total stockholders’ deficit		(30,034)		(40,154)
Total liabilities and stockholders’ deficit	$	183,082	$	177,250

PostRock Energy Corporation

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended June 30,
	2013		2014
	(in thousands)
Cash flows from operating activities
Net loss	$	(1,014)	$	(12,311)
Adjustments to reconcile net loss to net cash flows from (used in) operating activities
Depreciation, depletion and amortization		13,121		14,259
Share-based and other compensation		2,141		1,921
Amortization of deferred loan costs		215		260
Change in fair value of derivative financial instruments		(3,880)		3,502
Gain on disposal of assets		(10)		(78)
Gain on investment		(4,445)		(1,706)
Other non-cash changes to items affecting net loss		—		5,133
Changes in operating assets and liabilities
Accounts receivable		(768)		(416)
Accounts payable		(4,507)		(1,464)
Other		396		(649)
Net cash flows from operating activities		1,249		8,451
Cash flows from investing activities
Restricted cash		1,500		(56)
Proceeds from sale of securities		—		10,778
Expenditures for equipment, development and leasehold		(26,821)		(14,737)
Proceeds from sale of assets		194		538
Net cash flows used in investing activities		(25,127)		(3,477)
Cash flows from financing activities
Proceeds from debt		20,000		36,000
Repayments of debt		—		(41,000)
Debt and equity financing costs		(454)		(11)
Proceeds from issuance of common stock		4,075		—
Net cash flows from (used in) financing activities		23,621		(5,011)
Net decrease in cash and cash equivalents		(257)		(37)
Cash and equivalents beginning of period		525		37
Cash and equivalents end of period	$	268	$	—