Bass Energy & Exploration is independently owned and operated by the Bass family.
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Tensions between the U.S. and Venezuela are escalating, with Washington weighing tighter sanctions that could choke off vital heavy crude supplies. Analysts at Rystad Energy warn that if Venezuelan output is disrupted, the market will scramble to replace these unique barrels, likely driving up prices for Canadian and other heavy grades that U.S. refiners rely on.
A Rigzone analysis provides a sobering perspective on today’s oil prices. While crude is trading in the mid-$60s, inflation-adjusted pricing reveals that today's $67 barrel is equivalent to only about $44 in 2008 dollars. This suggests that despite nominal volatility, the real value of crude remains historically low, squeezing producer margins while benefiting consumers.
In a significant shift for U.S. imports, Iraq has sharply increased its oil shipments to the United States, reaching an average of 435,000 barrels per day last week. This surge makes Iraq the second-largest supplier to the U.S. for the week, highlighting strong American appetite for Middle Eastern sour crude to replace tighter global supplies.
The industry tidbit connects directly to the heavy crude story. Heavy crude is chemically complex but often yields a higher proportion of diesel than lighter grades. With winter demand heating up, any disruption to Venezuelan or heavy crude flows could tighten diesel markets specifically, impacting heating costs and industrial transport.
Europe’s resolve to sever its remaining energy ties with Russia is confronting pushback from within. A new EU agreement to phase out Russian fossil fuel imports by 2027 has not only angered Moscow but also exposed fissures inside the bloc.
The global oil landscape as 2025 draws to a close presents a striking paradox: crude is historically cheap in real terms, yet the security of supply is unusually fragile. On one hand, inflation has quietly eroded the value of oil – a barrel selling for around $67 today is equivalent to only ~$44 in 2008 dollars. Producers have managed to maintain these low real prices through remarkable efficiency gains, essentially creating a deflationary pressure in an inflationary world. On the other hand, the market’s complacency toward geopolitical risk is being tested. Escalating tensions between the U.S. and Venezuela threaten a potential supply shock in heavy crude, a niche but critical corner of the market that complex refineries depend on. In anticipation, U.S. refiners are reconfiguring supply lines toward the Middle East, evidenced by a surge in Iraqi oil imports to American shores. This report provides an in-depth analysis of these converging themes – the undervaluation of oil when adjusted for inflation, the looming risk of a heavy crude disruption, and the strategic realignment of crude flows – to assess whether markets are underpricing the risk of a sharper price move in 2026.
Despite nominal prices hovering in the $60s, the real buying power of oil revenue has fallen, forcing the industry into a continuous productivity race. That equilibrium has kept fuel cheap for consumers, but it rests on the assumption that stability persists. Now, with a major heavy-oil producer on the brink of conflict, that assumption is shakier. U.S. Gulf Coast refiners, highly optimized for heavier grades, have limited alternatives if Venezuela’s output is sidelined. They are already tapping Iraq and other suppliers to secure feedstock, but bottlenecks remain. As we detail in this report, any significant disruption of heavy crude flows could trigger outsized impacts on diesel and jet fuel prices, reverberating through the economy and even into global food prices via fertilizer links. In short, the market’s current calm – low real prices and manageable supply – belies a growing undercurrent of risk. Stakeholders should beware the fragile equilibrium: a market that appears well-supplied and “cheap” can be upended by a single geopolitical jolt.
To grasp where oil prices may head, we must first understand how surprisingly low they already are in real terms. Current crude prices around $65-$70 per barrel are misleading without context. Adjusted for inflation, they represent a far lower economic value than the same prices in the past. According to SEB Chief Commodities Analyst Bjarne Schieldrop, “today’s $67 per barrel is only $44 per barrel in 2008-dollars.” In other words, a barrel of oil buys roughly one-third less goods and services today than it did in 2008. The nominal price of oil is roughly unchanged from the mid-2000s, but the U.S. dollar has weakened in purchasing power by about 52% since then.
Schieldrop notes that the “fair price” of oil today – around $67 – happens to be similar to the average price from 2005–2008 in nominal terms. Back then, however, that same nominal price reflected much higher value. The fact that we’re at the same dollar price after nearly two decades of inflation means energy is historically cheap for consumers. Indeed, in real terms, oil-intensive goods like fuel comprise a smaller share of household budgets now than in the 2000s. The flip side is the stress on producers: the industry’s revenue, when converted to 2008 dollars, has shrunk dramatically per barrel. Schieldrop aptly frames it as the world getting cheaper oil “to the joy of consumers and to the terror of oil producers”. Upstream companies must now fight for efficiency and cost cuts simply to preserve margins at a $65–70 price that would have been lucrative in the past but is comparatively lean today.
Why haven’t oil prices risen to reflect this lost purchasing power? In a word: productivity. The oil industry has offset inflation through innovation and efficiency gains in production. Schieldrop’s analysis points out that if you assume a base extraction cost of ~$40 per barrel in 2008, a normal inflation rate of ~2.4% per year would add about $0.96 to the cost of producing each barrel annually. Over 17 years, that implies an increase of roughly $16–17 per barrel in the cost floor. By that logic, breakeven prices should be much higher today than they were in 2008. And yet, thanks to technology and efficiency improvements, the industry has managed to neutralize that $0.96/year cost creep through productivity gains.
The scale of these gains is remarkable. The world consumes on the order of 38 billion barrels of oil per year, so a $0.96 per barrel productivity improvement equates to about $36 billion saved per year, or roughly $182 billion in cumulative savings by 2030 if current trends continue. These savings stem from multiple innovations:
All these factors have allowed producers to pump more oil at lower unit cost, countering what would otherwise have been rising expenses due to inflation and resource depletion. In fact, if these productivity leaps had not occurred, Schieldrop estimates Brent crude would need to be around $100+ per barrel today just to incentivize sufficient supply. Instead, Brent has hovered in the $60s, and the market is balanced. The industry’s ingenuity effectively acted as a giant deflator, keeping nominal prices flat.
The current stability – relatively low nominal oil prices, underpinned by continual efficiency improvements – may not be permanent. The “low-hanging fruit” of the shale revolution is largely picked. Early on, drillers targeted the most productive zones (Tier 1 acreage) and achieved huge gains by simply drilling more wells, longer wells, and fracking them more intensely. Now, however, signs of diminishing returns are emerging. Companies in maturing shale basins are increasingly drilling Tier 2 or Tier 3 locations that are less geologically favorable. Productivity per new well has plateaued or even declined in some regions as the best spots get fully developed.
At the same time, general cost inflation has not vanished. The oilfield service sector faces higher labor and materials costs; steel, diesel fuel, and equipment have all become pricier in recent years. If the 2.4% annual cost inflation in the supply chain starts outpacing the productivity gains, producers will feel margin compression. In such a scenario, either investment and output will fall or prices will eventually have to rise to compensate. This acts as a structural price floor under oil. In other words, there is a limit to how long the industry can tread water – continuing to pump at high rates without higher prices – if underlying costs creep up.
Another factor is reserve depletion. The supermajors and OPEC alike must invest in new projects to replace declining fields. Many of those new barrels (deepwater, oil sands, or less prolific shale areas) carry higher production costs than the easy shale oil did. If investment lags due to low real prices, supply could tighten and push nominal prices upward. In summary, the current equilibrium of “cheap” oil is fragile. The oil market has been spoiled by a one-time revolution in extraction efficiency. As that revolution matures, market forces – or any external shock – could nudge prices higher to ensure producers remain profitable, especially in an inflationary macro environment.
What had been a long-simmering standoff between the United States and Venezuela is now reaching a boiling point. In late 2025, the U.S. significantly ramped up its military presence in the Southern Caribbean, deploying a carrier strike group led by the USS Gerald R. Ford along with an amphibious assault ship and supporting vessels. Thousands of U.S. troops and Marines are positioned within striking distance of Venezuela. In response, the Maduro government announced a “massive mobilization” of its own military forces and militias, framing the U.S. presence as a direct threat to Venezuela’s sovereignty. Caracas has even taken the unusual step of appealing to OPEC and OPEC+ members, with President Nicolás Maduro writing a letter accusing Washington of “illegal threats” and aggression that could destabilize the international oil market. This diplomatic outreach is likely an attempt to rally international opposition to any U.S. intervention by highlighting the risk to global oil supplies.
The prospect of conflict raises very real concerns for the oil market. Venezuela is no longer the oil giant it once was – current output is about 1.1 million barrels per day of crude (exports are a bit lower, around 0.8–0.9 million bpd). Yet what makes Venezuela pivotal is the type of oil it produces. A U.S. incursion, if it happens, could put this entire volume at risk of disruption. Analysts note that small-scale operations (e.g. targeted strikes against narcotics-related sites) might spare oil infrastructure. But anything beyond that – strikes on the regime or critical energy facilities – could send Venezuelan production tumbling. Past precedents are sobering: Venezuela’s oil industry was nearly brought to its knees in 2002–03 by a nationwide strike, collapsing from 3 million bpd to just 200,000 bpd in short order. A war could have an even more severe effect, especially if Maduro’s defense strategy includes sabotaging oil fields or export terminals as a form of retaliation. In a full-scale conflict scenario, experts warn Venezuelan output could be shut-in entirely for a time – and might take years to recover post-conflict, given the potential for infrastructure damage and political chaos.
A loss of Venezuelan oil is not just about the volume – it’s about the quality of the barrels lost. Much of Venezuela’s crude is extra-heavy and sulfur-rich. Refiners around the world cannot simply replace these barrels with light, sweet oil from Texas shale and call it a day. Complex refineries in the U.S. Gulf Coast, China, India and elsewhere have spent billions on coking units and desulfurization to process heavy crude. They need the dense, tar-like oil from places like Venezuela, Canada, or Mexico to produce a full slate of products. If those refineries run only light crude, they actually become less efficient – they produce excess gasoline and lack feedstock for diesel and other distillates, leaving some refinery units underutilized.
Currently, Venezuelan grades (like Merey crude) are an ideal fit for certain refineries, particularly in China. If suddenly removed, those refineries would be left scrambling. Rystad Energy emphasizes that while 1.1 million bpd is a blip in overall supply, the heavy-crude segment would tighten dramatically. Global heavy oil supplies were already constrained by earlier events (sanctions on Iran and Russia, Mexico redirecting oil to its own refineries, etc.). A Venezuela outage could force buyers in Asia and the U.S. to bid aggressively for the remaining heavy barrels from Canada, the Middle East, and Latin America. We could even see typically cheaper heavy grades flip to a premium over light oil – essentially a quality-driven price spike.
In North America, this scenario would likely manifest as higher costs for refiners and consumers. U.S. Gulf Coast refineries, configured for heavy feedstock, might have to cut utilization or pay a premium to import more Canadian oil. Canadian heavy crude (Western Canadian Select) prices would likely rise, and the spread between heavy and light oil could narrow or invert. Notably, analysts predict a Venezuelan disruption would lift the price of the Dubai crude benchmark relative to Brent, since Dubai is the marker for Middle Eastern medium/heavy oil widely used in Asia. In effect, a heavy-crude supply shock might send ripples through the entire pricing structure of the oil market.
There’s another often-overlooked vulnerability: Venezuela’s heavy oil depends on diluents to move. The oil is so viscous that it must be blended with lighter fluids (like naphtha or condensate) just to be pumped through pipelines. Historically, Venezuela imported naphtha from the U.S. for this purpose, until sanctions cut that off. It then turned to Iranian condensate and, more recently, to Russian naphtha shipments. As of H2 2025, Russia has become the primary supplier of diluent for Venezuela’s Orinoco Belt crude. This creates a strategic chokepoint: if a conflict or blockade prevents those Russian diluent cargoes from arriving (for instance, if the U.S. Navy intercepts shipments), Venezuelan heavy crude output would quickly grind to a halt even if oil fields themselves aren’t directly attacked. Without diluent, the oil can’t flow. In essence, a few tankers of naphtha are the lifeline keeping Venezuela’s heavy oil moving; cut that lifeline, and you effectively shut in production without having to bomb a single well.
A Venezuelan conflict could also trigger second-order effects far beyond the crude oil market. One immediate concern is diesel fuel. As noted, Venezuela’s heavy sour barrels are tailor-made for yielding a high proportion of diesel and jet fuel. The world diesel market is tight as it is – the International Energy Agency has warned of strained middle distillate supplies this winter. Remove Venezuela’s heavy crude from the equation, and diesel prices could surge disproportionately. This isn’t just a pocketbook issue for truckers; diesel is the workhorse fuel of the global economy, powering freight transport, farming equipment, and industrial machinery. A spike in diesel costs would feed into the price of virtually everything, potentially stoking inflation just as many economies are getting inflation under control.
More surprising is the potential impact on global food prices. How could turmoil in Venezuela affect food? The link is through fertilizer. Venezuela’s neighborhood includes one of the world’s major industrial fertilizer hubs: the Point Lisas petrochemical complex in Trinidad & Tobago, not far from Venezuela’s coast. This complex produces ammonia and other nitrogen fertilizers, which require natural gas and remain vulnerable to any regional conflict. Analysts have pointed out that a conflict could lead to disruptions at Point Lisas, either from collateral damage, accidental pipeline hits, or even cyberattacks and sabotage by Venezuela’s allies. If Trinidad’s ammonia production is knocked offline, the global fertilizer supply would tighten, since Trinidad is a key exporter. The result would be higher fertilizer prices, which in turn raise input costs for farmers worldwide. Food prices could then rise, echoing the kind of food inflation shock seen in 2022 when fertilizer became scarce. In short, an oil supply conflict in Venezuela has the potential to morph into a broader energy and food crisis, due to these interlinked systems. Policymakers would need to brace for such ripple effects – coordinating releases from strategic fuel reserves and possibly organizing alternative sources of fertilizer for agriculture – to mitigate the global fallout of a Caribbean conflict.
As Latin American heavy crude supply looks shakier, U.S. refiners aren’t waiting around. They’ve been quietly reshuffling their import slate, and Iraq has emerged as a big winner. According to the U.S. Energy Information Administration’s latest data, Iraq’s oil exports to the U.S. averaged 435,000 barrels per day in the first week of December 2025. That is a jump of ~149,000 bpd from the previous week. In fact, with that surge, Iraq became the United States’ #2 foreign oil supplier for the week, surpassing even Saudi Arabia in volume. Only Canada ships more oil to American shores. This is a remarkable shift: as recently as a couple of years ago, Iraq was a more modest part of the U.S. import mix, while countries like Mexico and Venezuela featured more prominently. Now Iraq is shouldering aside others to help fill America’s heavy oil needs.
It’s useful to put the latest figures in context. Overall U.S. crude imports fell to 4.87 million bpd last week (down over 800,000 bpd week-on-week), yet Iraq’s share rose – indicating U.S. refiners intentionally cut back lighter or more expensive imports and allocated more room to Iraqi barrels. Here’s a snapshot of the U.S. import hierarchy from that week, and what it signifies:
A few things stand out. Canada remains the stalwart, providing nearly 3.44 million bpd – over 70% of all U.S. imports. However, Canadian export capacity to the U.S. is essentially maxed out; new pipeline projects like the Trans Mountain Expansion (TMX) now send more Canadian crude to the Pacific Coast for export to Asia, marginally reducing what’s available to the U.S. Midwest and Gulf. Saudi Arabia’s shipments to the U.S. are relatively small (under 0.35 million bpd) and are often on term contracts – Saudi Aramco has been prioritizing Asian markets, and OPEC+ production limits keep a ceiling on their exports. Mexico’s contribution has collapsed to just 131,000 bpd, a dramatic decline from historical levels. Mexico’s new Dos Bocas refinery came online and began consuming the country’s flagship Maya heavy crude domestically, leaving very little for export (U.S. imports of Mexican crude in 2025 are roughly half their 2023 level). Venezuela’s token volume (122,000 bpd) exists only because of a U.S. sanctions waiver allowing limited imports via one company; that could disappear overnight with a policy change or any military action.
This leaves Iraq as the prime adjustable lever for U.S. refiners seeking heavy and medium crude. The jump to 435,000 bpd suggests U.S. buyers actively sought extra Iraqi cargoes – likely Basra Heavy or Basra Medium crude grades – to compensate for tightness elsewhere. It’s worth noting that Iraq itself produces primarily medium-sour oil, which, while not as dense as Venezuelan ultra-heavy, is a decent fit for refineries needing heavier feedstock. With Iraq now essentially tied with (or ahead of) Saudi Arabia in U.S. import volume, it underscores a shifting dynamic: the Persian Gulf is regaining importance in the U.S. energy supply chain, despite years of talk about “energy independence.” When push comes to shove, American refiners will seek out the barrels that suit their configurations, regardless of origin.
The reshuffling of import partners is all about managing risk and feedstock needs. U.S. refiners are clearly worried about heavy crude supply, and for good reason. As the table above shows, traditional sources of heavy oil in the Americas are diminished. Mexico’s exportable surplus of heavy crude is evaporating as it refines more domestically. Venezuela is politically unreliable and on the verge of potential conflict. Canadian heavy, while abundant, is logistically constrained – pipelines to the U.S. are full, and additional barrels increasingly find their way to other markets via new routes. In 2021 the U.S. also halted imports of another heavy source, Russian crude and vacuum gasoil, due to sanctions, which removed yet another option for refiners.
All this means the U.S. Gulf Coast refining system has a heavy crude deficit, which Iraq is now helping to plug. By courting Iraqi barrels, U.S. buyers diversify away from the Western Hemisphere and tap into Middle Eastern supply that can be more stable (Iraq is an OPEC member but outside of any U.S. sanctions regimes). The data essentially shows U.S. refiners hedging against the loss of Venezuela by securing oil from elsewhere in advance.
There is a geopolitical silver lining here for Washington. Strengthening oil trade ties with Iraq can have the effect of pulling Baghdad a bit away from Tehran’s orbit. Recent diplomatic analysis by Reuters noted that U.S. pressure played a role in Iraq’s decision to reopen a key oil pipeline to Turkey, despite Iranian-backed militia attacks in the region. The U.S. has been reasserting its influence in Iraq’s oil sector (for instance, ExxonMobil just agreed to re-enter southern Iraq oilfields). With Iraq’s economy deeply dependent on oil exports, having the U.S. as a major customer gives Washington some leverage. Iraq’s government, facing a widening budget deficit and project freezes due to delayed 2025 budget funds, badly needs steady oil revenue. Shipping more barrels to the U.S. (a reliably paying customer) directly benefits Iraq’s coffers at a critical time. This mutual benefit – U.S. refiners get heavy oil, Iraq gets revenue – also strengthens the overall bilateral relationship.
In summary, Iraq’s emergence as a top supplier to the U.S. is a strategic realignment born of necessity. It highlights how interdependent the global oil system remains. Even as U.S. crude production stays high, the particular quality of foreign oil still matters greatly. Heavy crude shortages can’t be solved by light shale oil, so the U.S. must turn abroad. Iraq is stepping into a role long held by Venezuela and Mexico, and in doing so, it is deepening its ties with the West.
Relying more on Iraqi oil is not without its own risks. While geographically removed from the Americas, Iraq’s stability and capacity to export at high volumes have uncertainties:
That said, the U.S.-Iraq oil connection has momentum and mutual interest behind it. The U.S. government likely welcomes Iraqi barrels as they reduce upward pressure on domestic fuel prices. Iraq, for its part, is eager to sell every barrel it can to fund its budget. As noted, Iraq heads into 2026 without a finalized budget and with a gaping fiscal deficit. Oil revenue is the lifeblood of Baghdad’s finances (over 90% of government revenue), so maintaining and increasing exports is a top priority. We may well see Iraq prioritize U.S. deliveries to keep this lucrative outlet open, even if it means juggling obligations to other buyers.
In essence, the heavy crude supply chain is being rewired in real-time. The U.S. is leveraging global supply networks – reaching across the Atlantic and Indian Oceans – to secure the types of oil it needs. This reduces exposure to the Venezuela scenario, but it introduces a new dependency on Middle Eastern stability. A decade ago, “energy independence” was a buzzword. Now, with heavy crude, we see that energy interdependence is the reality: North America’s energy security still partly hinges on decisions made in Baghdad, Riyadh, and elsewhere.
As we look ahead, oil market forecasts diverge sharply depending on whether one assumes a continuation of the status quo or a disruption scenario. Consensus among many analysts leans bearish for 2026, emphasizing robust supply and only moderate demand growth. For instance, Fitch Solutions (BMI) projects that Brent crude will average about $68.5 per barrel in 2025, barely changing at $67 in 2026. Their rationale – echoed by others like Standard Chartered – is that ongoing oversupply and weak economic momentum will keep prices in check. U.S. shale output, while not surging, is expected to remain high enough to meet incremental demand. Additionally, a softer demand outlook in key markets (e.g. China’s consumption growth slowing) and the anticipation of continued OPEC+ discipline contribute to this view. SEB’s analysts likewise noted that as of December, the market was in a mild surplus, with near-term prices actually trading below the 5-year forward price – a sign that traders see more supply than demand. In summary, the baseline case assumes no major drama: supply keeps pace, efficiency gains persist, and prices stay around the mid-$60s. Under such a scenario, inflation-adjusted oil would become even cheaper over time.
But the bullish case is lurking in the background, largely tied to geopolitical risk – especially the heavy crude issue. If the U.S.-Venezuela standoff results in a serious loss of Venezuelan output, it could be a game-changer. Even some relatively dovish organizations concede that a Venezuela conflict would create an upside shock. The Atlantic Council warns that while strategic reserves and spare OPEC capacity might blunt the immediate spike, the loss of heavy-sour barrels would “tighten already-strained diesel markets” and risk another bout of global inflation. Rystad Energy, as mentioned earlier, believes a full disruption (say, 1 million bpd offline) would materially lift global benchmarks. We could imagine Brent quickly rebounding to $80 or higher in that event, especially if combined with any other outages. Some market analysts have speculated Brent could test the $90-$100 range briefly if a conflict is prolonged – not unreasonable considering Brent neared $90 as recently as mid-2024 during supply cuts.
The key difference in the bullish scenario is the heavy-light crude spread. It’s not just about Brent or WTI rising; it’s about specific grades skyrocketing. Heavy Canadian or Middle Eastern crude prices could leap if refiners bid up limited supplies. This in turn feeds into diesel and jet fuel prices because those fuels come disproportionately from heavy feedstock. The International Energy Agency’s alert on tight diesel supply suggests any further strain could cause outsized price moves in that segment. Consumers might experience this as surging diesel at the pump and heating oil in the winter. Economically, that’s more damaging than a spike in crude alone, because it directly hits supply chains and households’ heating costs. In effect, the bullish case is a stagflationary oil shock: higher energy prices led not by booming demand, but by a supply cut and hitting the refining system where it’s least flexible.
Which scenario will prevail? Financial markets currently seem to assign a low probability to the worst-case outcomes. Oil’s forward prices remain in backwardation at relatively modest levels. However, it’s worth noting that the market’s risk pricing has been wrong before. In mid-2019, for example, oil prices were subdued even as tensions with Iran mounted – until half of Saudi Arabia’s oil processing capacity was knocked out by an attack, sending prices briefly soaring. Similarly, complacency can flip to panic very quickly in commodities. The heavy crude situation is a “fat tail” risk – low chance, high impact – that isn’t fully baked into most forecasts.
A critical question: if Venezuela’s barrels are removed, how much can others compensate? There is some slack in the system, but not a perfect replacement:
The implication is that a heavy crude shortfall would probably result in a period of adjustment. Refiners might temporarily change yield slates, produce more gasoline and less diesel from lighter feeds, or even slow down processing rates if they can’t find suitable crude. Over months, markets would find a new balance – perhaps encouraging more production from various places. But during that adjustment, price volatility could be extreme.
Bringing it all together, the oil market is perched on a delicate equilibrium. On one side, we have a seeming glut of resources made cheap by technological advances – a triumph of human innovation keeping inflation at bay. On the other side, we have rising geopolitical flames licking at one of the weak links in the oil supply chain – a reminder that physical realities and politics can upend even the best technological triumphs.
For industry players and policymakers, the takeaway is to not be lulled by the comfort of recent price stability. The fact that oil is “only $44 in 2008 dollars” is a testament to efficiency, but it should not breed complacency. If anything, it means producers have little financial cushion; any shock that raises their costs or disrupts output could force a swift price correction upward.
Key indicators to watch in early 2026 will be:
Consumers are enjoying reasonable fuel prices under an illusion of normalcy, while underneath, the decks are being reshuffled to keep supply flowing. Our analysis suggests the market might be underestimating the potential for a sharp move higher. Just as the industry engineered a way to defy gravity on cost, unforeseen events could rapidly undo those gains. The prudent course for market watchers is to stay alert to quality-specific supply issues and geopolitical flashpoints – they will matter just as much as headline inventory numbers or OPEC meetings in determining the trajectory of oil prices in 2026.
Bass Energy & Exploration is independently owned and operated by the Bass family.
Bass Energy & Exploration
7 NE 6th Street
Oklahoma City, OK 73104