W&T OFFSHORE INC annual report, FY2013

Business Context and Reporting Period

W&T Offshore, Inc. filed this Form 10-K for the fiscal year ended December 31, 2013, with quarterly data included for the fourth quarter. The company is an independent oil and natural gas producer focused primarily on the Gulf of Mexico and Texas, with exploration, development, acquisitions and production activities across offshore shelf, deepwater, deep-shelf and onshore properties.

2013 average production: 295.7 MMcfe/day, up from 280.9 MMcfe/day in 2012.
2013 production mix: approximately 39% oil and condensate, 12% NGLs and 49% natural gas on an energy-equivalent basis.
Year-end proved reserves: 117.7 MMBoe, essentially flat with 117.5 MMBoe in 2012; 50% oil, 13% NGLs and 37% natural gas.

Financial Performance and Key Metrics

Metric	2013	2012	Change
Revenue	$984.1 million	$874.5 million	+12.5%
Operating income	$146.7 million	$169.3 million	-13.3%
Net income	$51.3 million	$72.0 million	-28.7%
Basic and diluted EPS	$0.68	$0.95	Decreased
Net cash from operations	$561.4 million	$385.1 million	+45.8%
Capital expenditures	$634.4 million	$684.9 million	-7.4%
Cash and equivalents	$15.8 million	$12.2 million	Increased
Total long-term debt	$1.205 billion	$1.088 billion	+10.8%

Operating margin was approximately 14.9%, compared with 19.4% in 2012; net margin was approximately 5.2%, compared with 8.2%.
Oil revenue increased to $718.9 million, supported by a 16.3% increase in oil sales volumes, despite a decrease in realized oil prices to $102.44 per barrel from $104.35.
NGL revenue declined to $73.3 million as realized prices fell 11.8% to $35.07 per barrel.
Natural gas revenue increased to $189.3 million as realized prices rose 20.7% to $3.55 per Mcf, partially offset by a 1.1% decrease in sales volumes.
Lease operating expense increased 16.6% to $270.8 million, primarily due to higher workover activity, expanded onshore operations and acquired properties.
DD&A and ARO accretion increased to $451.5 million from $356.2 million, or $4.18 per Mcfe compared with $3.47 per Mcfe, reflecting higher development costs, reserve and ARO changes and acquisitions.
Interest expense incurred increased to $85.6 million from $63.3 million, reflecting the full-year effect of the $900 million of 8.50% Senior Notes.
2013 included $9.1 million of other income, primarily from an option exercised by a counterparty, and an $8.5 million net derivative loss.

Liquidity, Debt and Capital Allocation

Cash flow from operations of $561.4 million did not fully cover $634.4 million of oil and gas capital expenditures; financing activities provided $57.0 million.
At December 31, 2013, the company had $290.0 million drawn on its revolving facility, $509.6 million of undrawn availability, a borrowing base of $800.0 million and $0.4 million of outstanding letters of credit.
The revolving facility has total commitments of up to $1.2 billion, matures November 8, 2018 and is subject to semiannual borrowing-base redeterminations.
The company had $900.0 million principal amount of 8.50% Senior Notes due June 2019. Total contractual long-term debt principal was $1.19 billion.
The company was in compliance with applicable credit facility and senior note covenants at year-end.
2013 dividends totaled $58.8 million, including $31.8 million of special dividends. The board declared an additional $0.10 per share dividend payable March 31, 2014.

Material Changes Versus the Prior Comparable Period

Revenue and production increased, driven primarily by higher oil volumes, development at Ship Shoal 349, onshore production and the contribution from the 2012 Newfield acquisition.
Profitability declined despite higher revenue because lease operating expense, DD&A, ARO-related costs and interest expense increased.
Operating cash flow improved materially due to higher revenue, income tax refunds, lower tax payments and improved collections.
Capital spending shifted toward offshore and exploration: 2013 exploration and development spending was $507.1 million, including $143.7 million in deepwater and $62.0 million in deep-shelf spending.
W&T acquired the Callon Properties for $82.4 million of cash consideration, plus assumed ARO of approximately $4.2 million, and sold several non-operated Gulf of Mexico interests for combined net proceeds of approximately $11.9 million.
Proved reserves increased by only 0.2 MMBoe after 18.0 MMBoe of production, supported by 20.2 MMBoe of extensions and discoveries and 2.3 MMBoe from acquisitions, partially offset by downward revisions and asset sales.
Asset retirement obligations decreased to $354.4 million from $384.1 million after $81.5 million of settlements, but estimate revisions increased the liability by approximately $44.6 million.
A January 2014 review identified an erroneous third-party conversion factor that overstated reported 2013 natural gas volumes by including 1.9 Bcf attributable to prior periods. The adjustment had no effect on revenue or operating cash flow but increased DD&A by $5.0 million and reduced net income by $3.2 million.

Guidance, Outlook, Risks and Unusual Items

The 2014 capital budget is $450.0 million, excluding acquisitions, allocated 42% to exploration, 52% to development and 6% to other items; 68% is offshore and 32% is onshore.
Management expects to fund 2014 capital spending and potential acquisitions with operating cash flow, cash on hand, revolver borrowings and, if necessary, capital markets access. The budget is subject to change.
Management expects continued volatility and potential weakness in oil, NGL and natural gas prices. Lower prices could reduce revenue, liquidity, reserve values, borrowing capacity and compliance with debt covenants, and could trigger a full-cost ceiling-test impairment.
Pipeline outages, platform maintenance, weather and operational issues caused estimated production deferrals of approximately 13.0 Bcfe in 2013. The Mississippi Canyon 506 field remained shut in because of platform and pipeline outages.
The company received EPA notices proposing suspension and a three-year debarment from certain federal contracts, including future federal oil and gas leases, arising from prior environmental violations. The company is contesting the notices; the timing and outcome are uncertain.
BOEM challenged the company’s waiver of supplemental bonding requirements for offshore decommissioning obligations. A stay was extended through April 15, 2014 while negotiations continued. Additional bonding could increase costs and reduce revolver availability; the amount was not determinable.
The company pled guilty in January 2013 to two Clean Water Act counts relating to 2009 conduct, paid $1.0 million in fines and community service, and entered a three-year probation and environmental compliance program.
Insurance underwriters prevailed at the district court level in a dispute over Hurricane Ike removal-of-wreck coverage; W&T appealed. The company had incurred $45.7 million and expected an additional $1.9 million of related removal costs.
At year-end, the company had oil derivatives covering approximately 3.5 million barrels of anticipated 2014 production. Derivatives reduce price exposure but can limit gains if prices rise.
The company remains exposed to Gulf of Mexico hurricanes, uninsured or underinsured environmental events, accelerated decommissioning requirements, offshore regulatory changes, hydraulic-fracturing restrictions, water availability in Texas and third-party pipeline and platform dependency.

Most Important Facts for Investors to Verify

Whether the EPA suspension and proposed debarment are lifted, modified or imposed, and the effect on future federal lease participation.
The outcome of the BOEM supplemental-bonding dispute and the amount and timing of any required additional collateral.
Revolver borrowing-base redeterminations, covenant compliance and liquidity after capital spending, dividends and potential bonding requirements.
Actual 2014 production, pipeline restoration timelines and the impact of the Mississippi Canyon 506 outage and other deferred volumes.
Whether higher DD&A, ARO revisions or lower commodity prices lead to future ceiling-test impairments or reserve revisions.
The collectability and timing of Hurricane Ike insurance recoveries following the adverse district court ruling and appeal.
Progress in converting the $910.0 million of future PUD development requirements into producing reserves, particularly the 31.6 MMBoe of PUDs at year-end.
The effect of the 2014 conversion-factor correction on reported production, depletion expense and future operating metrics.
Customer concentration, including approximately 48% of 2013 sales to Shell Trading (US) Co., and continued access to third-party processing and transportation infrastructure.